GENERAL INTEREST — Quick Takes
BP to further reduce global upstream workforce by 2017
BP PLC has recently told its workforce of plans to further reduce staff in its global upstream oil and natural gas segment by yearend 2017.
In an e-mailed reply to OGJ, a spokesman for BP's US business segment said BP is planning an upstream organization at a segment level with a workforce of less than 20,000 people. "To reach this level," he said, "we will need to reduce our current workforce of BP employees and agency contractors by at least 4,000 additional people."
The cuts are "to simplify [BP's] business, improve efficiency, and reduce costs without, of course, compromising safety, which remains our No. 1 priority," the spokesman said.
The company would not be providing a running commentary on any other specific numbers or a breakout of headcount reductions for specific regions, the spokesman said.
Petrobras cuts 2015-19 capex by $32 billion
Petroleo Brasileiro SA (Petrobras) is reducing its planned capital expenditures for 2015-19 by $32 billion from the previously reported amount to $98.4 billion.
The new total is based on a newly projected average Brent crude oil price in 2016 of $45/bbl, down $10/bbl from the previous projection made last October. The company attributes the cut to portfolio optimization comprising $21.2 billion and an exchange rate effect of $10.7 billion.
The adjustments are expected to result in reductions in projected Brazilian oil production in 2016 to 2.145 million b/d from 2.185 million b/d; and, in 2020, to 2.7 million b/d from 2.8 million b/d.
Petrobras's 2015 oil production in Brazil averaged 2.128 million b/d, slightly higher than the target of 2.125 million b/d and 4.6% higher than 2.034 million b/d in 2014. Intended divestments in 2015-2016 will remain at $15.1 billion (OGJ Online, Oct. 6, 2015). The company divested $700 million in 2015.
Saudi Aramco considering equity options
Saudi Aramco said it is studying various options to allow broad public participation in its equity.
One option includes the listing in capital markets "of an appropriate percentage of the company's shares." Another option is listing "a bundle" of Aramco's downstream subsidiaries.
Once the study is complete, the findings will be presented to the board, which will make recommendations to the Saudi Aramco Supreme Council. Aramco said the study is consistent with the direction pursued by the kingdom for reforms, including privatization in various sectors of the Saudi Arabian economy and deregulation of markets.
Suncor extends offer for Canadian Oil Sands
Suncor Energy Inc. is extending its offer for all the outstanding shares of Canadian Oil Sands Ltd. (COS) to Jan. 27 (OGJ Online, Dec. 30, 2015).
"We are encouraged by the number of shares that have been tendered," said Steve Williams, Suncor's president and chief executive officer.
Suncor made the unsolicited offer on Oct. 5. An expiration date of Dec. 4, 2015, was extended to Jan. 8 (OGJ Online, Dec. 4, 2015). COS said shareholders overwhelmingly rejected the offer and that Suncor has an immediate obligation to disclose the actual tender results.
Exploration & Development — Quick Takes
Fieldwood signs Mexican offshore PSC
Fieldwood Energy E&P Mexico, a subsidiary of Houston-based Fieldwood Energy LLC, signed a production-sharing contract for Area 4 in the Bay of Campeche, awarded as part of Mexico's Round 1 second tender (OGJ Online, Sept. 30, 2015).
The area, comprising the proved but undeveloped Ichalkil and Pokoch fields in 100-150 ft of water, will be operated by Fieldwood in consortium with PetroBal SAPI de CV, a subsidiary of Mexican conglomerate Grupo Bal.
Fieldwood will commence a 2-year appraisal period in Area 4 beginning early this year, during which time it intends to conduct a limited drilling program and technical evaluation process.
Italy's Eni SPA in December signed a PSC for development of Amoca, Mizton, and Tecoalli oil fields in Area 1, awarded in the second tender (OGJ Online, Dec. 2, 2015). The company plans to drill four delineation wells.
Isobel Deep redrill confirms North Falkland discovery
Premier Oil PLC's Isobel Deep redrill, 14/20-2, has confirmed the oil discovery of the original well in May 2015 (OGJ Online, May 28, 2015). The well, which is on licence PL004A, 30 km south of Sea Lion field, reached TD at 3,014 m encountering oil-bearing intervals in a number of sandstone reservoirs between 2,564-2,861 m, the base of the Isobel Deep sand.
No oil-water contacts were encountered in the gross oil-bearing interval of about 300 m, Premier said. The company will use existing 3D seismic to determine future plans and the extent of the discovered resource. Operations have been suspended and the well will be plugged as planned. The rig is moving to the Chatham well location.
Robin Allan, Premier exploration director, noted, "The results of this well confirm the success of the Isobel Deep 14/20-1 well announced in May last year. We have encountered a substantial oil bearing interval, which confirms the potential of this part of the North Falkland basin as a standalone discovery."
Premier holds 36% operating interest in the well. Rockhopper Exploration PLC holds 24%, but this will soon increase to 64% once its merger with Falkland Oil & Gas Ltd. is completed at the end of January. Announced in November 2015, the all-share merger was valued at £57.1 million (OGJ Online, Dec. 7, 2015). Once combined, the resulting company will be the largest license holder in the North Falkland Islands, the companies said.
Lundin updates drilling campaign offshore Malaysia
Lundin Malaysia BV, a wholly owned subsidiary of Lundin Petroleum AB, completed the Imbok-1 exploration well on Blocks SB307 and SB308, offshore Saba, East Malaysia (OGJ Online, Dec. 8, 2015). The well, which was drilled using the West Prospero jack up rig, encountered minor oil shows. The well has been plugged.
At the close of Imbok-1, the same rig is now drilling Lundin Malaysia's Bambazon exploration well near the Imbok-1. The company expects drilling to take 25 days. The prospect lies in shallow water to the north of St. Joseph oil field, also on Blocks SB307 and SB308. The well will target Miocene-aged sands.
Lundin Malaysia holds 85% working interest in SB307/308 and partner Petronas Carigali Sdn. Bhd. holds 15%. Lundin Malaysia operates six blocks in Malaysia, including PM307, PM319, PM308A, PM328, SB303, and SB307/308.
Buru makes oil find onshore Canning basin
Buru Energy Ltd., Perth, has found oil in a new play in its Ungani Far West-1 wildcat in production licence L21 in the onshore Canning basin of north Western Australia.
The company has identified a sandstone reservoir at the top of the Anderson formation at a depth of 1,560 m. The reservoir has a good permeability of 450 md. Oil was subsequently recovered to the surface.
Buru reported that interpretation of pressure data indicates an oil column at least 14 m thick with about 5 m of net pay. The company is currently logging and taking samples to confirm and evaluate the find.
Once this operation is completed, drilling will continue to the top of the main target Ungani Dolomite reservoir where 5-in. casing will be run. The company will then bring in a specialist coring rig to core through the dolomite reservoir section.
Although oil has previously been found in and produced from the Anderson formation in the Canning, this was on the Lennard Shelf in the company's Blina field permits 125 km away on the other side of the basin.
The Ungani Far West discovery is a significant new play in the Ungani region and upgrades numerous surrounding leads and prospects in the shallow zone overlying the main dolomite reservoir.
Drilling & Production — Quick Takes
Eni brings Mpungi field on production offshore Angola
Italy's Eni SPA has started deepwater production from Mpungi field on Block 15/06 offshore Angola, reaching a third milestone in the West Hub development project.
Mpungi field is 350 km northwest of Luanda and 130 km west of Soyo. Its production follows the West Hub's production from Sangos field in November 2014 and Cinguvu field in April 2015 (OGJ Online, Apr. 29, 2015).
The West Hub is expected to ramp up production to 100,000 b/d during the first quarter. The West Hub encompasses development of Sangos, Cinguvu, Mpungi, Mpungi North, Ochigufu, and Vandumbu fields in 1,000-1,500 m of water.
The wells are connected to the N'Goma floating production, storage, and offloading unit, which has a treatment capacity of 100,000 b/d.
Eni operates Block 15/06 with 36.84% stake. Other joint venture partners are Sonangol Pesquisa e Producao 36.84% and SSI Fifteen Ltd. 26.32%.
Block 15/06 also includes the East Hub development project, which is under development and expected to come on stream in 2017.
Tullow updates upstream activity in Africa
Tullow Oil PLC reported that the Tweneboa-Enyenra-Ntomme (TEN) development project offshore Ghana is more than 80% complete and on track to begin production in July or August (OGJ Online, Nov. 13, 2014).
The floating production, storage, and offloading vessel for TEN is expected to arrive in Ghana in early March after an expected late January departure from Singapore. A gradual increase in production is anticipated during this year's second half as the facilities go through the final commissioning stage and wells are tied into the FPSO.
Also in Ghana, Tullow said Jubilee field gross production in 2015 averaged 102,600 b/d (OGJ Online, Aug. 17, 2015). Tullow is forecasting production to reach 101,000 b/d in 2016 due to a planned 2-week FPSO maintenance shutdown in the first quarter and a period of reduced water injection capacity.
The Greater Jubilee Full Field Development Plan, which includes Mahogany and Teak fields, was submitted to Ghana's government in December, Tullow said. Approval is targeted for this year's first half. The project-to extend field production and increase commercial reserves-has been redesigned to reduce the overall capital requirement and allow flexibility in the timing of the capital investment.
In Kenya, meanwhile, Tullow said it spudded the Cheptuket-1 exploration well on Block 12A in the Kerio Valley basin on Dec. 28, 2015, with the PR Marriott Rig-46 and will likely complete drilling in February (OGJ Online, Dec. 15, 2015).
EIA: US shale oil output to fall 116,000 b/d in February
Crude oil production in February from seven major US shale plays is expected to fall 116,000 b/d to 4.83 million b/d, according to the US Energy Information Administration's latest Drilling Productivity Report (DPR). EIA last month also projected a 116,000-b/d loss for January (OGJ Online, Dec. 7, 2015).
The DPR focuses on the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica, which altogether accounted for 95% of US crude oil production increases and all US natural gas production increases during 2011-13.
Production from the Eagle Ford is seen dropping 72,000 b/d during the month to 1.15 million b/d, followed by a 24,000-b/d loss in the Bakken to 1.1 million b/d and 23,000-b/d loss in the Niobrara to 371,000 b/d.
Continuing to demonstrate its resiliency, the Permian is forecast to increase 5,000 b/d to 2.04 million b/d.
New-well oil production/rig across the seven plays is expected to increase by a rig-weighted average of 3 b/d to 497 b/d. The Niobrara is again seen leading the way, expected to post a 16-b/d jump to 726 b/d, while the Utica is seen rising 12 b/d to 294 b/d and Eagle Ford rising 9 b/d to 804 b/d.
Shale gas production in February is expected to decrease 405 MMcfd to 43.72 bcfd, mostly reflecting a 225-MMcfd loss in the Marcellus to 15.22 bcfd, 140-MMcfd loss in the Eagle Ford to 6.46 bcfd, and 76-MMcfd loss in the Niobrara to 4.1 bcfd. Increases, meanwhile, are seen from the Utica, up 43 MMcfd to 3.25 bcfd; Haynesville, up 16 MMcfd to 6.23 bcfd; and Permian, edging up 1 MMcfd to 6.91 bcfd.
PROCESSING — Quick Takes
Suriname commissions newly expanded refinery
Suriname state oil firm Staatsolie has completed the long-planned major expansion and efficiency project to double crude processing capacity and expand fuel production at the Tout Lui Faut refining complex about 12 miles south of the country's capital city of Paramaribo (OGJ Online, Sept. 9, 2009).
Fully commissioned during December 2015, the expansion has more than doubled the refinery's crude capacity to 15,000 b/d from its previous 7,000 b/d to produce high-quality diesel and gasoline meeting the latest European quality standards, Staatsolie said.
Designed to reduce Suriname's dependence on imported fuel products, the expansion took more than 10 years to complete from prefeasibility studies, which began in 2004, to its December 2015 startup (OGJ Online, Apr. 11, 2014; July 28, 2011).
Most recently scheduled for commissioning in October 2014 (OGJ Online, Jan. 21, 2014), and partially commissioned in December 2014, the project faced a series of delays resulting largely from higher construction costs, according to the company.
After briefly shutting down following a Dec. 13, 2015, fire at a pipeline flange that leads to a vacuum distillation unit (VDU), the refinery resumed operations on Dec. 15 and now processes 15,000 b/d of Suriname's low-sulfur, low-metals Saramacca crude to produce the following: ultralow-sulfur diesel, 8,000 b/d; ULS gasoline, 2,500 b/d; fuel oil, 6,000 b/d; bitumen, 100 b/d; and sulfuric acid, 100 b/d.
While Staatsolie's expanded ULSD production will be enough to satisfy Suriname's entire local demand, increased gasoline production from the refinery still falls short of fulfilling demand on the regional market, the company said.
Despite the shortfall in gasoline supply, Staatsolie said the refinery's overall expanded fuel production will reduce Suriname's need for foreign fuel imports by about $100 million/year.
According to a July 2008 environmental impact assessment for the project, the expansion was to include the following additions: a VDU, a visbreaker unit, a hydrocracking unit, a hydrogen production unit (including a pressure-swing adsorption unit), a catalytic reforming unit (including a new naphtha splitter), a light naphtha isomerization unit, a sulfuric acid unit, and new and revamped utilities for newly added units.
Petrobras cleared to boost crude runs at Rnest
Petroleo Brasileiro SA (Petrobras) has received approval from state regulators to lift crude oil throughputs to levels nearing full design capacity at the first 115,000-b/d production train of its Abreu e Lima refinery (Rnest) at the port of Suape, near Recife, the capital of Brazil's Pernambuco state.
Pernambuco's Agencia Estadual de Meio Ambiente (CPRH), the state's environmental agency, issued a renewal of Rnest's operating license on Jan. 11, the terms of which allow the refinery's first crude distillation unit (CDU) to process as much as 100,000 b/d.
The newly renewed license, valid through Jan. 10, 2017, follows an initial operating permit issued in December 2014 that limited the CDU's crude processing capacity to 74,000 b/d, or about 64% of its nameplate capacity (OGJ Online, Dec. 5, 2014).
While the new license allows Rnest to operate before completing installation of its U-93 emissions abatement unit (SNOX), it also stipulates the refinery must process crudes that are lower in sulfur than the heavier, high-sulfur crude for which the plant was designed.
In addition to a host of reporting requirements, Petrobras must meet certain progress deadlines with regard to implementation of Rnest's SNOX unit, as well as its central waste system, according to the license.
Early in 2015, Petrobras commissioned the first of Rnest's two 75,000-b/d delayed coking units, as well as an 82,000-b/d diesel hydrotreater as part of the refinery's Phase 2 startup (OGJ Online, Mar. 19, 2015; Mar. 13, 2015).
Once fully operational, Rnest will have the capacity to process 230,000 b/d of 16° gravity oil for the production of mainly low-sulfur diesel, but petroleum coke, LPG, and heavy coker gas oil, as well as naphtha.
Originally scheduled for startup last year, a firm timeline for commissioning of Rnest's second phase remains unclear.
Nynas completes takeover of German refining assets
Nynas AB of Sweden has completed its takeover of Royal Dutch Shell PLC's former Harburg refining assets in Hamburg, Germany, to operate as a specialty lubricants refinery.
Nynas, which initially assumed operations of the refinery's base oil manufacturing plant and crude distillation unit (CDU) in the site's northern sector from Shell Deutschland Oil GMBH in January 2014, will use the refinery to produce as much as 330,000 tonnes/year of specialty oils and bitumen for sale to Europe, the company said.
Currently undergoing a conversion and upgrade, the refinery's CDU is scheduled for restart during spring 2016.
A new bitumen truck-loading terminal due to be operational by midyear will complete a series of planned improvements to the refinery's infrastructure, Nynas said.
The final transfer of Harburg operations to Nynas follows the European Commission's September 2013 approval of the transaction to prevent shortfalls in production of certain oil products for Europe after Shell demonstrated that it was no longer economically sustainable to operate the refinery in its former configuration, which would have led to its complete shutdown (OGJ Online, Sept. 3, 2013).
Shell will still operate the rest of the Harburg site.
TRANSPORTATION — Quick Takes
First cargo ships from Australia Pacific LNG project
The first cargo of LNG has departed from the Australia Pacific LNG (APLNG) facility on Curtis Island in Queensland, the project's partners reported.
Construction of the $24.7-billion (Aus.) Origin Energy Ltd.-led APLNG project began in 2011 and consists of two 4.5 million-tonne/year capacity production units.
The cargo was shipped on the Methane Spirit carrier, which left Gladstone harbor earlier this month. It is a year since BG Group shipped its first cargo from an adjacent plant.
At the peak of its construction, the APLNG project created 15,000 jobs and is the third coal seam gas-LNG project completed in Queensland in the last year. BG's plant (QCLNG) has two trains in production, while Santos Group (GLNG) has one train and Origin's APLNG one train in production. Both GLNG and APLNG are scheduled to begin production from second trains this year.
Origin has said APLNG needs oil prices of $38-42/bbl before it yields distributions above operating and financing costs. Brent oil prices closed at $33.55/bbl on Jan. 8.
In December 2015, Origin attempted to insulate itself from plunging oil prices by hedging some of APLNG's output at $40/bbl. It also sold forward some cargoes at a fixed price to an undisclosed buyer.
On a broader front, Australia shipped 25 million tonnes of LNG in 2014-15 earning $16.9 billion (Aus.) in export revenue.
By 2019-20 when all seven LNG projects developed in recent years-QCLNG, GLNG, APLNG, Gorgon-Jansz, Wheatstone, Ichthys, and Prelude-are fully operational, there will be a projected combined Australian export volume of about 76 million tpy.
Waitsia gas field project gets financial approval
AWE Ltd. and Origin Energy Ltd., both of Sydney, have given financial approval for the first stage of the 484-bcf Waitsia gas field development onshore Perth basin in Western Australia.
This initial phase involves connecting the Waitsia-1 and Senecio-3 wells to the nearby refurbished Xyris production facility. There will be installation of new systems and upgrades to existing assets. Treated gas from the Xyris plant will be sent to the existing Parmelia pipeline to Perth.
Operator AWE says engineering, execution, and management costs for Stage 1 will amount to $17.5 million (Aus.).
Construction will include two 4-in. flowlines from the two wellheads to a northern gathering manifold and then a 6-in. pipeline to the Xyris plant.
Initial capacity will be 10 terajoules/day of produced gas, which is expected on stream in August. Further expansion of capacity will be possible.
The joint venture has signed a take-or-pay sales agreement with Alinta Energy for 10 terajoules/day for 2½ years. Price of the gas was not disclosed.
First-stage production will provide early cash flow along with data to help optimize future plans for full field development.
The anticipated flow when fully developed is expected to be more than 100 terajoules/day, representing 10% of Western Australia's daily domestic consumption.
AWE also is evaluating the potential for codeveloping the nearby Senecio-Synaphea-Irwin tight gas fields, which potentially contain a further 237 bcf of gas.
AWE and Origin each hold equal interest in the Waitsia project.
