GENERAL INTEREST — Quick Takes
Redford sees rail issues entering Keystone XL debate
Some US officials raised greenhouse gas concerns as increasing amounts of Alberta's heavy crude oil move by rail while approval of the Keystone XL pipeline's cross-border permit continues to be delayed, Premier Allison Redford said after concluding her fifth Washington visit to lobby for the project.
"A lot of that product is being transported by rail at the moment, and that is something that is receiving quite a bit of attention in the United States, partly because we know that transportation by rail leads to higher greenhouse gas emissions than a pipeline would," The Financial Post reported Redford as saying.
The premier met with officials at the US Department of State, which is expected to conclude its environmental impact statement early in 2014 on TransCanada Corp.'s revised application for a cross-border permit, as well as US Senate and House leaders.
The proposed 1,179-mile pipeline would move diluted bitumen from Alberta's oil sands to US Gulf Coast refineries for processing. It also would provide capacity to transport lighter crude from the Bakken shale in North Dakota and Montana.
US Sen. Mary L. Landrieu (D-La.), who cosponsored legislation with Sens. John Hoeven (R-ND) and Max Baucus (D-Mont.) expressing support for Keystone XL, said it should have been approved years ago as she met with Redford.
"I'm going to do everything I can, working with colleagues on both sides of the aisle, to get the pipeline built, use the great refining capacity of Louisiana and Texas, and harness the capacity for investment in clean environmental technology to help produce the energy that [North America] needs," Landrieu said.
Redford also met with House Energy and Commerce Committee Chairman Fred Upton (R-Mich.) and Rep. Lee Terry (R-Neb.), who chairs the committee's Manufacturing and Trade Subcommittee.
"Beyond just the Keystone XL pipeline, we are going to need to build many more pipelines, transmission lines, and private sector infrastructure projects as part of the architecture of abundance to keep up with the remarkable pace of US and Canadian energy production," said Upton, who cosponsored with committee member Gene Upton (D-Tex.) HR-3301 which would standardize cross-border permit reviews for new energy infrastructure.
Progress Energy to acquire Montney properties
The Progress Energy Canada Ltd. subsidiary of Malaysia's Petroliam Nasional Bhd. will acquire an interest in two Montney-related partnerships from Talisman Energy Inc.
The acquisition will include 127,000 net acres of Montney lands and 11,000 b/d of oil equivalent production as of Oct. 1. Output is expected to increase in this year's fourth quarter.
Progress Energy said, "These natural gas interests are an attractive complement to our existing North Montney asset base in northeastern British Columbia and are among the largest remaining North Montney lands not dedicated to a potential [LNG] project.
"The location, resource potential, and operational synergies of these assets make this an ideal fit that expands our British Columbia resource base and increases our land position to 1.2 million acres," the company added.
The acquisition will include wells, pipelines, and gas processing plants in the Greater Farrell and Great Cypress areas. Progress Energy will acquire Talisman's 50% interest in Greater Farrell, where Talisman's partner owns the remaining 50% interest.
Under the terms of the Talisman partnership, the partner pays a disproportionate share of development costs. The value of this "capital carry" is $870 million at the Oct. 1 effective date and will be used to fund a portion of Progress Energy's share of capital investments in Greater Farrell area over the coming years.
The capital carry offsets the total Progress Energy acquisition cost of $1.5 billion. In addition, Progress Energy will acquire Talisman's partnership interest in the Greater Cypress area where Progress Energy has joint operations with Talisman. The acquisition is subject to customary closing conditions and adjustments, including the approval of Industry Canada.
Petrobras to merge with two of its subsidiaries
Petroleo Brasileiro SA (Petrobras) has approved mergers with Companhia de Recuperacao Secundaria (CRSec) and the spun-off portion of Petrobras International Finance Co. (PIFCo), both wholly owned Petrobras subsidiaries.
Petrobras said both mergers are intended to reduce costs and simplify and streamline the corporate structure of Petrobras Group. The company's capital will not increase and no new shares will be issued. Shares representing the capital of these subsidiaries will be extinguished.
CRSec operated in the financial structuring of the secondary recovery project for the Campos basin's Pargo, Congro, Garoupa, Cherne, and Carapeba fields. After liquidating all contractual obligations, Petrobras exercised the call option of all of CRSec shares. The merging process allows for the adequate return of CRSec assets to Petrobras.
Luxembourg-based PIFCo raised capital overseas, facilitating the sale of oil and oil products. Petrobras said successive changes to Brazilian tax legislation prompted the discontinuance of the subsidiary's activities.
Certain assets and liabilities related to PIFCo's commercial activities will be transferred to Petrobras. PIFCo will be dissolved after its remaining assets and liabilities, related to capital-raising activities and loan transactions with companies in the Petrobras Group, will be merged into Petrobras Global Finance BV–PGF.
That PIFCo merger will not affect Petrobras's guarantees and commitments relating to subsidiary-issued bonds, which will continue to be unconditionally and irrevocably guaranteed, Petrobras said.
In 2001, PIFCo priced a $500 million senior note issue. The notes were scheduled to mature in June 2011 (OGJ Online, July 2, 2001).
Exploration & Development — Quick Takes
Petrobras to flow-test Iara presalt well
Petroleo Brasileiro SA (Petrobras) will conduct formation tests of reservoirs encountered at the fifth exploratory well in the Iara presalt area of the Santos basin offshore Brazil.
The company drilled the 3-RJS-715D (3-BRSA-1181D-RJS) well, informally known as Iara steep angle, in 2,128 m of water on the BM-S-11 block 225 km off Rio de Janeiro. It drilled the high-angle well in the central area of the concession's discovery evaluation plan some 4 km north of 1-RJS-656 (1-BRSA-618) discovery well, informally known as Iara.
The wellbore, designed and executed with a subhorizontal geometry, extends to 6,672 m measured depth and penetrated 900 m of carbonate rock below salt. A 310-m hydrocarbon column was identified. Reservoir characteristics are similar to those found in the vertical discovery well that encountered good quality 28° gravity oil.
The group of Petrobras operator with 65% interest, BG E&P Brasil 25%, and Petrogal Brasil 10% will proceed with activities outlined in the discovery evaluation plan approved by Brazil's National Petroleum Agency ANP.
Statoil makes third Norwegian Sea oil discovery
Statoil ASA and its partners in PL 348/348B have made an oil discovery 15 km northeast of Njord field in the Norwegian Sea's Snilehorn prospect.
The volume of the discovery ranges 55-100 million bbl of recoverable high-quality light oil.
Exploration well 6407/8-6 and sidetrack 6407/8-6A, which was drilled by the Songa Trym drilling rig, have proved several oil columns in Jurassic-aged formations. The main wellbore also has proved oil at a deeper level in reservoir rocks of Triassic age, possibly Grey Beds formation.
"A most likely future development of the Snilehorn discovery will be via the Hyme production system to Njord, or as a direct tie-in to the Njord platform," commented Arve Rennemo, vice-president and asset owner of Njord.
Statoil said the Snilehorn well results have provided new information about the Halten Bank area in the Norwegian Sea's shallow water.
"This is probably the first time hydrocarbons have been proven in Grey Beds formation in this part of the Norwegian Sea," said Gro G. Haatvedt, Statoil senior vice-president for exploration on the Norwegian continental shelf. "This will be confirmed by further analyses of the data and may imply further upside potential in this area."
The company has now made three near-field discoveries in the Norwegian Sea in as many months—Njord, Norne, and Asgard—proving 86-166 million boe total recoverable.
In August, Statoil and partners discovered gas-condensate in Smorbukk North in the Asgard area. The company said the discovery's preliminary reserves volume is 25-47 million boe recoverable (OGJ Online, Aug. 20, 2013). The following month, it discovered oil in Svale North in the Norne area, with a possible 6-19 million bbl recoverable oil (OGJ Online, Sept. 16, 2013).
Exploration wells 6407/8-6 and 6407/8-6A are in the Norwegian Sea's PL348/348B. Statoil is operator with 35% interest, with partners GDF Suez E&P Norge AS 20%, E.On E&P Norge AS 17.5%, Core Energy AS 17.5%, Faroe Petroleum Norge AS 7.5%, and VNG Norge AS 2.5%.
Miocene oil confirmed in Oyo field offshore Nigeria
The Allied Energy PLC-operated Oyo-7 well on OML 120 offshore Nigeria, first well to penetrate Miocene in Oyo field, has confirmed the presence of oil in Miocene.
The well found hydrocarbons in three intervals totaling 65 ft as interpreted from logging while drilling data, said partner CAMAC Energy Inc., Houston. CAMAC said it will integrate the results into studies to solidify further exploratory plans on OML 120 and 121.
Oyo field's regular oil pay is in Pliocene, and CAMAC Energy said Oyo-7 successfully achieved its primary and secondary objectives and will be temporarily suspended. Drilling of the horizontal section and completion are to start in the first quarter of 2014. The well should go on production in mid-2014.
Oyo field, which began producing in December 2009, is in 200-500 m of water 75 miles off southern Nigeria. Block interests are Allied Energy 70% and CAMAC Energy 30%.
Drilling & Production — Quick Takes
Petrobras starts production from Papa-Terra
Petroleo Brasileiro SA (Petrobras) and a Brazilian subsidiary of Chevron Corp. have begun crude oil production from Papa-Terra's floating production, storage, and offloading vessel offshore Brazil.
Papa-Terra is a heavy oil development in 3,900 ft of water on Block BC-20 in the southern Campos basin about 70 miles southeast of Rio de Janeiro. Discovered in 2003, it contains Brazil's first tension-leg wellhead platform, the P-61, expected to begin production next year. Papa-Terra has installed capacity to produce 140,000 b/d of crude.
Petrobras initially canceled the Papa-Terra bid process in 2009 because of uncertain market conditions, suspending the tenders for building the P-61 platform and P-63 FPSO (OGJ Online, Jan. 19, 2009). A year later, the company proceeded with development (OGJ Online, Jan. 27, 2010).
The P-63 FPSO left the Quip-Honorio Bicalho shipyard in Rio Grande, Brazil, for Papa-Terra in June to assist in increasing oil production to reach Petrobras's overall production target of 2.75 million b/d by 2017 (OGJ Online, June 20, 2013).
Petrobras is operator of Papa-Terra with 62% interest while Chevron holds 37.5%.
Ukraine, Chevron sign shale gas agreement
Ukraine has signed a production-sharing agreement with Chevron Corp. and the country's state-owned Nadra Oleska for shale gas production at Oleske field in western Ukraine, Worldwide News Ukraine reported. Chevron said the field covers 1.6 million acres. Nadra Oleska and Chevron will receive equal shares in the deal.
In January, Ukraine signed a PSA with Royal Dutch Shell PLC for Yuzivske shale gas field, a move that aligns with the government's initiative to reduce dependence on Russian gas (OGJ Online, Jan. 25, 2013). As part of the deal, Shell is required to give 31-60% of produced gas to the country. Shell received exploration rights for Yuzivske in September 2012 (OGJ Online, Sept. 7, 2012).
The country has made an effort in recent years to attract foreign investments in its upstream sector by altering its tax and legal framework. In addition to Chevron and Shell, Italy's Eni SPA and ExxonMobil Corp. have received PSAs from Ukraine (OGJ Online, June 3, 2013).
PROCESSING — Quick Takes
Western Refining buying Minnesota refinery
Western Refining Inc., El Paso, has entered into a definitive agreement to acquire the general partner interest and a 38.7% limited partner interest in Northern Tier Energy, which operates the 89,500-b/d St. Paul Park Refinery in Minnesota.
Western Refining will acquire the interests for total consideration of $775 million from ACON Investments LLC and TPG Capital LP, which acquired the refinery from Marathon Petroleum Co. LP for an estimated $900 million in 2010 (OGJ Online, Oct. 6, 2010). ACON and TPG formed Northern Tier Energy and took the company public as a master limited partnership based in Ridgefield, Conn., in July 2012.
Limited partner units not acquired by Western Refining are publicly traded.
In addition to the refinery, Western Refining will acquire a 17% interest in a 455,000-b/d crude oil pipeline; products terminals, storage tanks, rail facilities, and Mississippi River dockage; and retail assets including 163 company-operated convenience stores and 74 franchised convenience stores mainly in Minnesota and Wisconsin.
The refinery, which has fluid catalytic cracking and reforming capacities, processes 75% light and 25% heavy feedstocks.
Western Refining operates refineries in El Paso (128,000 b/d) and near Gallup, NM (23,000 b/d).
Indonesian refinery resumes limited operations
Indonesia's state-owned PT Pertamina (Persoro) and PT Trans-Pacific Petrochemical Indotoma (TPPI), a subsidiary of PT Tuban Petrochemical Industries, have resumed limited operations at TPPI's Tuban refining and petrochemical complex in East Java Province.
The refinery's restart is part of a tolling agreement between TPPI and Pertamina following the approval of a restructuring plan related to TPPI's 2012 bankruptcy.
Under terms of the agreement, Pertamina will operate the refinery for 6 months, affording TPPI the opportunity to gain income through the tolling fee from the collaboration to help meet debt payment obligations, according to a recent release from Pertamina.
During the 6-month operational period, the plant will run at a capacity of 55,000-80,000 b/d to produce a total of 530,000 tonnes of refined petroleum products, according to Pertamina. Yields will include about 2.8 million bbl of light naphtha, 1.5 million bbl of gas oil and fuel oil, and 36,000 tonnes of LPG, the state-owned company said.
Pertamina also confirmed it will supply feedstock in the form of condensate and naphtha to the Tuban plant, which houses a 100,000-b/d condensate splitter that started up in 2006 (OGJ, Dec. 15, 2008, p. 44).
"The reoperation of the Tuban TPPI refinery holds a very important role for supplying and developing petrochemical and fuel industries in Indonesia," Pertamina said in the release, reiterating the importance of the plant's operation in helping reduce imports of fuel, LPG, and other petrochemicals into the country.
Over the last decade, Pertamina has planned several projects aimed at reducing fuel imports into Indonesia by boosting domestic supplies, the most recent of which involves modernization of five of the company's existing refineries in the country (OGJ Online, Oct. 7, 2013; Aug. 30, 2013; Mar. 3, 2009; Feb. 15, 2009; Feb. 15, 2006).
Citgo restarts distillation unit at Lemont
Citgo Petroleum Corp. has successfully resumed operations at the atmospheric distillation tower of its 167,000-b/d Lemont, Ill., refinery following a fire that damaged the crude unit late last month (OGJ Online, Oct. 24, 2013).
A Citgo spokesman told OGJ that the company restarted the atmospheric section of the crude unit on Nov. 11.
"The vacuum section of the unit has been isolated and will undergo full repairs before being restarted—no timetable has been established for the restart of the vacuum section," said Pete Colarelli, Citgo's government and public affairs manager for the Lemont refinery.
The refinery's delayed full-restart follows an interim court order filed by the state of Illinois on Nov. 8, under which Citgo cannot resume operations of the fire-impacted vacuum distillation unit until the company has demonstrated it is safe to do so (OGJ Online, Nov. 11, 2013).
While Citgo previously confirmed some downstream units have continued to operate in the wake of the fire (OGJ Online, Oct. 29, 2013), identification of those units as well as the refinery's current crude oil processing capacity remain unavailable.
TRANSPORTATION — Quick Takes
ExxonMobil, BHP get nod for Scarborough LNG scheme
ExxonMobil Corp. and BHP Billiton's proposed plan to develop the Scarborough natural gas field discovery on the Exmouth plateau offshore Western Australia has received conditional approval from Australian Environment Minister Greg Hunt.
Initial plans are for a floating LNG (FLNG) development, but there is no guarantee as yet that this will be the final design (OGJ Online, Apr. 2, 2013). It would be larger than the FLNG facilities being built for Shell's Prelude field in Browse basin further north.
The FLNG vessel will be 495 m long and 75 m wide. Shell's Prelude is 488 m by 74 m. The Scarborough vessel will be capable of processing 6-7 million tonnes/year of LNG compared with Prelude's 3.6 million tpy.
Front-end engineering and design for the Scarborough FLNG vessel is slated to begin in 2014 with a final investment decision not due until the 2015 fiscal year.
The Scarborough JV's environmental application described the project as processing gas from 12 wells to be drilled during two phases from 2018.
The minister's conditions of approval relate to precautions to protect humpback and other whales that migrate through the region. The approval also stipulates corridors for any telecommunications cables to be used for communication with the FLNG vessel.
Scarborough field, discovered in 1979, contains 8-10 tcf of dry gas. Depending on the project being declared viable, FLNG would begin production in 2021.
KMEP launches open season for Marcellus NGL
Kinder Morgan Energy Partners LP (KMEP) and MarkWest Utica EMG LLC have started a binding open season to solicit commitments for a proposed Y-grade pipeline project to transport natural gas liquids produced from the Utica and Marcellus shales to Mont Belvieu, Tex.
The pipeline will have an initial design capacity of 150,000 b/d and would be expandable to 400,000 b/d with the addition of pump stations, and is projected to be in service in second-quarter 2016. The open season concludes Dec. 20.
The pipeline requires converting more than 1,000 miles of KMEP's 24-in. and 26-in. Tennessee Gas Pipeline system, currently in natural gas service, from Mercer, Pa., to Natchitoches, La. Two hundred miles of new pipeline of similar diameter will be built from Natchitoches to a proposed KMEP-MarkWest Utica joint venture fractionation facility with a third party that has facilities at Mont Belvieu.
In August 2012, MarkWest Energy Partners said it would add more than 600 MMcfd of processing capacity for the Marcellus and Utica, along with 140,000 b/d of fractionation, resulting in the capacity to operate 2.3 bcfd of processing and 300,000 b/d of fractionation for Northeast US shale plays (OGJ Online, Feb. 1, 2012). Operations began last week on two new cryogenic gas processing plants serving shale production in the Marcellus and Utica (OGJ Online, Nov. 8, 2013).
MarkWest Utica is a joint venture of MarkWest Energy Partners LP and Energy & Minerals Group.
CNOOC ups ownership to 50% of Queensland project
China National Offshore Oil Corp. (CNOOC) will move to a 50% interest in Train 1 of the Queensland Curtis Island coal seam gas-LNG project, operated by BG Group.
BG sold a further 40% of the project to the Chinese company for $1.93 billion to add to its existing 10% interest.
Under a separate agreement, BG is to supply CNOOC with another 5 million tonnes/year of LNG for 20 years beginning in 2015. This LNG will come from BG's global portfolio of assets.
The Queensland Curtis LNG deal includes CNOOC receiving a 20% interest in reserves and resources of some BG permits in the Walloon Fairway region of the Surat basin taking its share there to 25%. In addition CNOOC gets a 25% equity in other BG permits in the Bowen and Surat basins.
CNOOC will have the option to participate in up to 25% in one of the possible expansion LNG Trains at QCLNG on Curtis Island.
BG and CNOOC will jointly invest in construction of two LNG carriers in China, taking the number of committed vessels to four.
However the agreements exclude CNOOC gaining any interest in Train 2 facilities, the transmission pipeline, and the project's common facilities.