OGJ Newsletter
GENERAL INTEREST — Quick Takes
Shell anticipates loss of 2,800 jobs after BG merger
Following completion of its proposed merger with BG Group PLC, Royal Dutch Shell PLC says it expects an overall potential reduction of 2,800 jobs globally across the group, or 3% of the total combined group workforce (OGJ Online, Apr. 8, 2015). Shell deems the moves necessary to "achieve the expected benefits of the recommended combination, including previously disclosed and reported-on pretax synergies of $3.5 billion."
With BG's business expected to be integrated into Shell's business, Shell proposes that office consolidation is undertaken "where practical" in certain locations around the world. With regards to office footprint rationalization in the UK, Shell says it will, following deal completion, undertake a comprehensive review during the course of 2016.
The reductions are in addition to previously announced plans to reduce Shell's headcount and contractor positions by 7,500 globally. The newly proposed changes are subject to deal completion, engagement with affected employees, and relevant employee representatives.
Shell says further detailed work will be undertaken on the details of the proposed operational and administrative restructuring as part of ongoing integration planning. The deal remains on track for completion in early 2016.
Magnum Hunter files for bankruptcy protection
Magnum Hunter Resources Corp., Irving, Tex., has filed for Chapter 11 bankruptcy in a restructuring that involves $200 million in debtor-in-possession financing and conversion of debt into equity.
The company said support of creditors for its restructuring plan will enable it to emerge from bankruptcy with greatly diminished debt next April.
It has entered a restructuring support agreement with lenders that hold nearly all its first-lien debt, 66.5% in principal amount of its second-lien debt, and 79% in principal amount of its senior unsecured notes.
The agreement provides for conversion into equity of nearly all of Magnum Hunter's prepetition funded indebtedness and 100% of the company's contemplated postpetition debtor-in-possession financing.
The debtor-in-possession financing is a senior secured multidraw term loan backstopped by lenders in the restructuring support agreement. Magnum Hunter expects the financing to support stabilization of the company's operations. The debt-equity conversion will occur when the company exits bankruptcy.
On Sept. 30, Magnum Hunter reported total assets of $1.457 billion and total liabilities of $1.117 billion. For the first 9 months of 2015 it had a loss of $232 million, compared with a $234 million loss in the comparable period of 2014.
The company's operations are mostly in the Marcellus and Utica shale regions of the Appalachian basin. The company also has interests in acreage and production in Kentucky and has primarily nonoperating leasehold working interests in the Williston-Bakken shale region of North Dakota.
Magnum Hunter also has 45% equity ownership interest in Eureka Hunter Holdings LLC, which is not part of the bankruptcy.
Exploration & Development — Quick Takes
Contract let for Odd Job field in deepwater gulf
Deep Gulf Energy II LLC (DGE) has let a lump-sum contract to Technip SA to develop its Odd Job field on Mississippi Canyon Blocks 214 and 215 in the Gulf of Mexico. The ultradeepwater development lies offshore New Orleans in 4,800 ft of water.
Technip's scope will include project management and engineering services, installation of 23 km of pipe-in-pipe flowlines, and 2 km of steel catenary riser. The company also will design, fabricate, and install an in-line sled and flowline end termination. The offshore installation is expected to be completed by summer 2016, and will be performed with Technip's Beep Blue ultradeepwater pipelay and subsea construction vessel.
DGE operates Odd Job field and has several fields in development nearby. SOB II is on Mississippi Canyon Blocks 387 and 431, and Marmalard is slightly to southwest on Blocks 255 and 256. The field will be developed as a subsea tieback to the nearby Delta House FPS (OGJ Online, Apr. 17, 2015). Start of production is expected late in 2016.
Tullow finds oil in Etom-2 well in northern Kenya
Tullow Oil PLC said an exploratory well drilled in the South Lokichar basin in northern Kenya encountered 102 m of net oil pay in two columns.
The Etom-2 well, on Block 13T, was drilled to 1,655 m by the PR Marriott Rig-46 (OGJ Online, Nov. 17, 2015). Drilling followed evaluation of 3D seismic that was shot after the Etom-1 well (OGJ Online, Sept. 3, 2014).
Tullow said oil samples, sidewall cores, and wireline logging all indicate the presence of high API oil in the best quality reservoir encountered in the South Lokichar basin.
Tullow operates Blocks 13T and 10BB and has 50% interest. Africa Oil Corp. has 50%.
In Block 10BB, Tullow said it has completed the Ngamia extended well test, producing 38,000 bbl. Five completed zones of Ngamia-8 were tested at a cumulative rate of 2,400 b/d. All except the lowest zone produced naturally.
Tullow said the Marriott rig will move to Block 12A to spud the Cheptuket-1 well in the Kerio Valley basin.
Mubadala Petroleum, CNPC sign agreement
Mubadala Petroleum has signed a nonbinding agreement with China National Petroleum Corp. (CNPC) that identified potential future collaboration in the upstream oil and gas sector outside of UAE. More specifically, the national operating companies are identifying onshore conventional projects, offshore development, and LNG projects for future cooperation.
"This agreement reflects a growing level of dialogue between ourselves and CNPC…with expanding international interests," said Mubadala Petroleum Chief Executive Officer Musabbeh Al Kaabi. Details of any specific opportunities and commercial discussions remain confidential between the two operators.
Mubadala Petroleum operates a growing portfolio of producing assets in Southeast Asia. The latest of these is Nong Yao, which is in the Gulf of Thailand and came on stream in June (OGJ Online, June 18, 2015). The company is now the second-largest oil producer in Thailand. It also has several other projects under appraisal and development in the region.
Drilling & Production — Quick Takes
NEB: Oil sands output to hit 3.3 million b/d by 2020
Canadian oil sands production is expected to reach 3.3 million b/d by 2020, up from 2.5 million in November, the National Energy Board said (OGJ Online, Nov. 11, 2015).
In situ production will be responsible for the majority of the increase, but production from mining will also increase.
The November oil sands production number represents 60% of Canada's total oil production of 4.1 million b/d.
Overall expenditures to build or expand major oil sands projects in 2015 are expected to be $15 billion, down more than 30% from 2014. NEB said cancelled or deferred projects due to low oil prices now total more than 700,000 b/d.
Suncor advances Meadow Creek East SAGD work
Suncor Energy Inc. has taken a commercial step in the long-proposed Meadow Creek thermal oil sands project in Alberta as it awaits action on an amended development application.
The operator let a contract to Jacobs Engineering Group for project management and engineering services to complete the design basis memorandum for the renamed Meadow Creek East steam-assisted, gravity drainage project 45 km southeast of Fort McMurray.
Under the proposed amendment, Suncor and partner Nexen Energy ULC plan two replicated central process facilities able to produce 40,000 b/d each. The amendment application, filed in October, envisions construction start in 2017 and first production in 2020.
Initial development will involve 21 well pads, a cogeneration plant with capacity of 180 Mw, and supporting equipment. Ultimately, the project might have as many as 60 well pads and 560 SAGD well pairs to support production as high as 80,000 b/d over a project life of 25-40 years. The original Meadow Creek project received commercial approval for single-stage development of 80,000 b/d of production capacity in 2003 when Petro-Canada was operator. The plan received draft environmental approval that wasn't finalized.
Suncor absorbed Petro-Canada in a 2009 merger.
The updated project covers 13,270 hectares, compared with the original 12,478 hectares. The original project involved 322 Mw of cogeneration capacity and an initial 38 well pads with potential for an additional 41 pads (OGJ Online, Dec. 4, 2001).
Moho Phase 1b off Congo starts production
Total SA has started production from Moho Phase 1b, 75 km offshore Pointe-Noire, Congo (Brazzaville). The project, which lies in 750-1,200 m of water, is operated by Total and has a production capacity of 40,000 boe/d.
Moho Phase 1b involves the drilling of 11 subsea wells and the installation of the two most powerful subsea multiphase pumps in the world, Total says. It is tied back to the existing floating production unit (FPU) in Moho Bilondo field, producing since 2008.
Moho Phase 1b targets reserves in the southern portion of the Moho Bilondo permit area. In the northern portion, the Moho Nord development, launched concurrently with Moho Phase 1b in 2013, is ongoing and will add a further 100,000 boe/d of capacity (OGJ Online, Mar. 22, 2013).
Moho Phase 1b and Moho Nord are part of the Moho Bilondo license operated by Total E&P Congo with 53.5% participating interest. Partners are Chevron Overseas (Congo) Ltd. 31.5% and the Societe Nationale des Petroles du Congo 15%.
"Moho Phase 1b is our ninth start-up since the beginning of the year and will contribute to our strong production growth in the years to come," noted Arnaud Breuillac, Total president, E&P. "It follows the start-up of Dalia Phase 1A on Angola's Block 17 in July this year (OGJ Online, July 21, 2015), and more recently, the Lianzi field, which straddles the deep offshore of Congo and Angola (OGJ Online, Nov. 2, 2015)."
Total has maintained a presence in the Republic of the Congo for almost 50 years. Subsidiary Total E&P Congo operates 10 of the country's 23 producing fields, accounting for nearly 50% of national output, the company says. Total's equity production averaged 95,000 boe/d in 2014.
Total E&P Congo is owned by Total with 85% interest and a subsidiary of Qatar Petroleum with 15%.
Woodside-led Greater Western Flank gets green light
The Woodside Petroleum Ltd.-led Greater Western Flank project Phase 2 on the North West Shelf off Western Australia has been given the go ahead. The GWF-2 development will tap 1.6 tcf of 2P raw gas reserves from a total of six medium-size gas fields using subsea infrastructure.
The fields-Keast, Dockrell, Sculptor, Rankin, Lady Nora, and Pemberton-will be connected by a 35-km, 16-in. pipeline to the existing Goodwyn A platform for initial processing before being fed into the main trunkline to the North West Shelf LNG and domestic gas facilities on Burrup Peninsula.
Total investment in GWF-2 is estimated to be $2 billion. The project is slated to come on stream during second-half 2019.
Initial production will come from a total of five wells in Lady Nora, Pemberton, Sculptor, and Rankin fields and followed during first-half 2020 by a total of three wells in Keast and Dockerell fields.
Woodside says GWF-2 is the fourth major gas development within the North West Shelf gas project in the last 7 years. It is described as a robust project that will deliver significant value as a tie-back to the main NWS facilities and extending the plateau production.
NWS project participants are Woodside, BHP Billiton Petroleum, BP Developments Australia, Chevron Australia, Japan Australia LNG (MIMI), and Shell Australia, all with 16.67% interest.
PROCESSING — Quick Takes
Shell shutters ECC in Singapore for maintenance
Royal Dutch Shell PLC has initiated a maintenance shutdown of the ethylene cracking complex (ECC) at its Pulau Bukom manufacturing site on Bukom Island, Singapore, to execute work intended to stop accelerated external corrosion at the unit (OGJ Online, Apr. 2, 2015).
While Shell continues to assess the situation and conduct ongoing inspections during the maintenance period, the company has declared a force majeure on base chemical products from Singapore, Oliver Tabbert, a spokesman for Shell, told OGJ via e-mail.
The company, however, is working with customers on alternate sources of supply to minimize potential impacts as a result of the maintenance closure, Tabbert said.
Timeframes for the lengths of the maintenance shutdown and force majeure were not disclosed.
Shell previously shuttered the Singapore ECC and declared force majeure on products from Pulau Bukom for several days in mid-October after an unidentified operational upset at the plant (OGJ Online, Oct. 19, 2015; Oct. 16, 2015).
Following a debottlenecking and expansion project completed earlier in the year, the Singapore ECC has an ethylene production capacity of more than 1 million tonnes/year.
Bahrain lets contract for refinery modernization
Bahrain Petroleum Co. BSC (Bapco) has let a contract to WorleyParsons Ltd. to provide project management services for the planned expansion and modernization of its 267,000-b/d refinery at Sitra, on Bahrain's eastern coast.
As project management contractor, WorleyParsons will help Bapco to manage, monitor, and appraise firms engaged to deliver front-end engineering and design; engineering, procurement, and construction; and other services for the Bapco modernization program (BMP) at Sitra, WorleyParsons said.
Designed to optimize the refinery's configuration in order to keep it competitive beyond 2020, the BMP intends to integrate several new units into the plant's existing operations that will increase Sitra's total crude processing capacity to 360,000 b/d, the service provider said.
WorleyParsons valued the contract at $120 million (Aus.).
Bapco, which awarded a few contracts for the BMP project last year (OGJ Online, Oct. 9, 2014; Sept. 16, 2014), said the project also will improve the quality and yield of finished petroleum products produced at the refinery.
Initiated in 2012 and planned for execution in a series of phases over 6 years, the refinery modernization will include the staged implementation of at least five units, including a residue hydrocracker, vacuum gas oil hydrocracker, diesel hydrotreater, sulfur recovery unit, and delayed coker, according to Bahrain's National Oil & Gas Authority.
KMG unit wraps maintenance of Romanian refinery
Rompetrol Rafinare SA, a subsidiary of Kazakhstan's state-owned KazMunaiGaz, has completed a major turnaround of its 5 million-tonne/year Petromidia refinery in Navodari, Romania, on the Black Sea.
Wrapping in late November, the plant-wide turnaround, which occurs every 5 years, required an investment of $77.5 million and included both corrective and preventative maintenance and technical inspections designed to keep the refinery operating at its nominal capacity, Rompetrol Rafinare said.
The refinery, which has resumed normal production rates, is now operating at a planned crude processing rate of 14,000 tonnes/day, with the plant's mechanical availability reaching 96.5% as a result of the scheduled maintenance work, according to Yedil Utekov, general director of Rompetrol Rafinare.
Despite the refinery's more than month-long planned shutdown for execution of turnaround activities, the company estimates Petromidia's overall finished product output to average 5 million tpy for 2015, Utekov said.
While the company informed investors in August that this year's turnaround would include equipment inspections, routine maintenance, and catalyst replacement, details regarding other specific projects completed during the 2015 planned shutdown were not disclosed.
In 2013, Rompetrol Rafinare executed an upgrade and expansion program at Petromidia to increase the refinery's crude processing capacity as a means of assuring competitiveness of Kazakh crude-based products in the Black Sea market, the company said in its annual report for 2014.
UAE firm inks deal for refinery in Pakistan
Al Motahaden Petroleum Refineries (AMPR) of the United Arab Emirates is planning to invest $500 million to build a grassroots refinery in Pakistan's northwest province of Khyber Pakhtunkhwa. AMPR signed a memorandum of understanding for the project with the government of Pakistan's board of investment (BOI) on Dec. 10, BOI said.
As part of the MOU, AMPR has agreed to form a consortium consisting of local and foreign companies to develop the project, the first phase of which would have a crude processing capacity of 15,000-20,000 b/d with a planned future expansion to 50,000-100,000 b/d, BOI said.
In consideration of AMPR's proposed investment, BOI said it will extend its full assistance and support to the company in obtaining all administrative and regulatory approvals, consents, and permissions related to the project's development, including land acquisition as well as duty exemptions for delivery and import of equipment and machinery necessary to complete the refinery on time. A potential timeframe for the project's commissioning was not disclosed.
The Pakistani government previously signed an MOU with state-owned Pakistan State Oil to build a 40,000-b/d refinery at a cost of $600 million in Kohat district of Khyber Pakhtunkhwa that was to be fully commissioned by 2016-17 (OGJ Online, Apr. 12, 2013).
TRANSPORTATION — Quick Takes
Gorgon-Jansz LNG poised for first carrier arrival
The Chevron Australia group is poised for a major milestone in its Gorgon-Jansz LNG development on Barrow Island with the imminent arrival of a first LNG carrier.
The milestone contains a twist, however. The carrier will arrive with a full cargo of LNG that will be injected into the LNG plant on the island to cool the storage tanks and processing lines as well as purge any air that remains in the system.
The arrival of the carrier is a precursor to Chevron starting up the first of the three trains nearing completion in preparation for bringing the plant on stream.
The maiden cargo of Gorgon LNG is expected to leave Barrow Island in February or March.
Commissioning of Train 1 and its associated infrastructure is well advanced. Currently Chevron is undertaking final testing of critical systems required for the safe import of the commissioning cargo.
The first of the Jansz-Io wells was recently opened to the subsea pipeline linking the offshore fields to the Barrow production facilities.
At the same time Chevron is preparing to make the transition from constructor to production operator. The company also is working to have its other Western Australian project-the two-train Wheatstone development near Onslow-ready for production by yearend 2016.
Australia Pacific LNG comes on stream
The Origin Energy Ltd.-led Australia Pacific LNG (APLNG) coal seam gas-to-LNG (CSG-LNG) project has been brought on stream on Curtis Island near Gladstone on the central east coast of Queensland. The $24.7-billion (Aus.) project is the third CSG-LNG development on Curtis Island following the BG Group and the Santos group in the past 12 months. APLNG's first LNG shipment is expected before yearend.
Concept to completion has been more than 7 years and employed some 15,000 personnel in the Surat-Bowen basin fields and on Curtis Island work. Origin with 37.5% is partnered by ConocoPhillips, also 37.5%, and Sinopec with 25%.
Sinopec is also the major customer for the LNG with an agreement to take 7.6 million tonnes/year for 20 years. Kansai of Japan will take 1 million tpy for 20 years.
Depressed oil prices mean that cash flows from APLNG-and the BG and Santos plants-will be lower than originally anticipated, in the initial years at least.
The three Curtis Island plants, representing in excess of $70-billion (Aus.) investment, are the first in the world to produce LNG from a CSG feedstock.
NAM study cites benefits of oil pipeline construction
New crude oil pipelines could significantly benefit US manufacturers and the general economy as they are constructed, a study commissioned by the National Association of Manufactures concluded.
"For manufacturers, this study illustrates yet another reason why the administration, Congress, and our state and local leaders should be encouraging crude oil pipeline investment," said Ross Eisenberg, NAM vice-president, energy and resources policy, on Dec. 10 as the IHS Economics report was released.
Among its highlights, the study found that in 2015:
• Another 6,805 miles of domestic crude transmission pipelines were contracted at a cost of $11.57 billion, on top of 61,379 miles of US onshore crude pipelines operating at yearend 2014.
• Crude pipelines supported 276,497 construction and maintenance jobs, including 26,884 manufacturing positions.
• Crude pipelines contributed $31.4 billion to the gross domestic product, including $4 billion from manufacturing.
• Top employing industries for US crude pipelines include fabricated metals, machinery, chemicals, nonmetallic minerals, and primary metals.
• At least 66 different manufacturing subsectors, out of 86 total, have benefited from US construction of crude pipelines by $10 million or more, including iron and steel, fabricated metals, cement, machinery, and paints and coatings.