BHP Billiton hopes to divest US onshore business
BHP Billiton Ltd. said it's "actively pursuing options" to sell its US onshore oil and gas business, which it has classified as noncore amid pressure from shareholders to divest.
The Melbourne-based firm reported upward revisions in capital spending for its 2018 financial year due in part to an increase in US onshore drilling and development expenditure. While it looks for buyers, BHP said it will proceed with well trials, acreage swaps, and assessing midstream solutions.
BHP has more than 838,000 net acres in the Eagle Ford, Permian, Haynesville, and Fayetteville. The Black Hawk area of the Eagle Ford and the Permian area are two of its largest liquids-focused field developments.
"We certainly have plenty of people interested in taking a look," BHP Chief Executive Officer Andrew Mackenzie told reporters during an earnings call on Aug. 21. "The shale acquisitions were poorly timed. We paid too much," he explained (OGJ Online, Aug. 22, 2017).
BHP's US onshore operated rig count was five as of June 30, with three rigs in the Haynesville, one in Black Hawk, and one in the Permian.
Merger to combine companies in STACK play
Silver Run Acquisition Corp. II has agreed to merge with privately held Alta Mesa Holdings LP, Houston, and Kingfisher Midstream LLC, forming a company valued at $3.8 billion with operations in Oklahoma's STACK play.
Alta Mesa holds 120,000 contiguous net acres with about 4,200 gross identified drilling locations in the eastern Anadarko basin play. Since 2012, it has drilled 205 horizontal wells to total depth in the updip STACK oil window.
It expects estimated ultimate recovery at yearend to exceed 650,000 boe/well, about 140 boe/ft of lateral hole.
Alta Mesa is Kingfisher Midstream's anchor producer. Kingfisher owns more than 300 miles of pipeline, 50,000 bbl of crude storage capacity, and 60 MMcfd of gas-processing capacity. A cryogenic-plant expansion will add 200 MMcfd of processing capacity in the fourth quarter.
The midstream company, owned and operated by ARM Energy Holdings LLC, has 300,000 gross dedicated acres from Alta Mesa and other third-party customers.
James T. Hackett, chairman and chief executive officer of Silver Run II, will be executive chairman of the combined company, to be renamed Alta Mesa Resources Inc. He's a former chairman and chief executive officer of Anadarko Petroleum Corp. who earlier served as president and chief operating officer of Devon Energy Corp.
Hackett is a partner in Riverstone Holdings LLC, which formed Silver Run II to acquire and develop energy businesses.
Top managers of Alta Mesa will remain in place. They are Harlan H. Chappelle, chief executive officer; Michael E. Ellis, chief operating officer; and Michael A. McCabe, chief financial officer.
RimRock buying Whiting Williston assets
RimRock Oil & Gas Williston LLC has agreed to buy properties in the Bakken-Three Forks play of the Williston basin from Whiting Petroleum Corp. for $500 million cash.
Second-quarter production from the properties net to Whiting's interest averaged 7,785 boe/d.
The purchase covers 29,637 net acres in the Fort Berthold Indian Reservation area of Dunn and McLean counties, ND. Included are 29 nonoperated drilling spacing units and 17 operated units.
Whiting said it will apply proceeds to bank debt of $550 million.
DOE to sell 14 million bbl of sour crude from SPR
The US Department of Energy plans to draw down and sell 14 million bbl of sour crude oil from the US Strategic Petroleum Reserve, the DOE's Fossil Energy Office (FEO) reported on Aug. 22. The crude will be sold from three sites-Bryan Mound and Big Hill in Texas and West Hackberry in Louisiana, FEO said.
The announcement came a week after FEO announced an upcoming sale of SPR crude to fulfill requirements under the 2016 21st Century Cures Act and the 2015 Bipartisan Budget Act. Of the 14 million bbl, 9 million bbl will be sold to comply with the first law and 5 million bbl will be sold to comply with the second, FEO said.
Bids must be received no later than 2 p.m. CDT on Aug. 30, it noted. Contracts for winning bids will be awarded no later than Sept. 13, and deliveries will be take place in October and November.
Any company registered in the SPR's Crude Oil Sales Offer Program is eligible to participate in sales of crude from the reserve, FEO said. Other interested companies may register through the SPR web site's Crude Oil Sales Offer Program, it said.
The White House proposed selling nearly half of the SPR's crude over 10 years beginning in fiscal 2018 as part of the proposed federal budget it released in May.
China, Philippines eye joint exploration
China and the Philippines are discussing joint exploration of an area off the island nation claimed by Beijing.
Philippines Department of Foreign Affairs Sec. Alan Peter Cayetano confirmed during a press conference he had received approval from President Rodrigo Duterte to pursue an agreement.
The Philippines wants to include what it calls Rector Bank in the South China Sea in an oil and gas licensing round.
China claims the area, which it calls Reed Bank, along with much of the entire sea.
In July 2016, the Philippines government won a challenge to the Chinese claim in the United Nations Permanent Court of Arbitration. Duterte has not pressed for enforcement of the finding.
The Philippines government suspended exploration of the disputed area in 2014. But it has expressed worry about depletion of deepwater Malampaya natural gas field off Palawan Island, production from which fuels generation of 25% of the electricity used on the main island of Luzon.
Shell Philippines Exploration BV operates the Malampaya project in a joint venture with Chevron Malampaya LLC and state-owned PNOC Exploration Corp.
Greece launches new tender
Greece's Ministry of Environment and Energy has invited interested parties to submit bids within 90 days from the date of publication of its tender notice in the Official Journal of the European Union.
The tenders were published in the Greek gazette on Aug. 11. Yannis Bassias, director at Hellenic Hydrocarbons Resources Management SA (HHRM), told OGJ, "Although the Greek gazette published the tenders, the official 90-day competition period will start from the day the European gazette publishes the tenders, probably in September."
The international tenders are in the Ionian Sea west of Greece and west-southwest of Crete. The promotions are initiated by an expression of interest submitted by the joint venture of Total SA, ExxonMobil Corp., and Hellenic Petroleum (Helpe), which seeks to develop the area offshore Crete. The western Greece Ionian block has been submitted by Energean Oil and Gas.
In addition to seismic packages, HHRM is also making available all well data outside previously awarded blocks. The offshore wells Patra 1, West Katakolon 1, 1A, and 2, and the onshore Katakolon 101, 102, 103, 104, and 105 are not available commercially but can be reviewed in the ministry's data room.
Cairn upgrades offshore Senegal oil resources
Cairn Energy Ltd. has increased its estimate of recoverable resources in SNE oil field offshore Senegal.
The Edinburgh-based company is operator of a group that includes Australian companies FAR Ltd. and Woodside Petroleum Ltd.
Cairn says the most recent appraisal work has prompted it to raise its estimates for the discovery to 563 million bbl, which is up from 473 million bbl in its previous forecast.
Cairn says the group expects to make a final investment decision on the project at yearend 2018 and will be looking to bring the field on stream in 2021-23 if the go-ahead is given.
Cairn believes the project will break even if the oil price is in the low $30/bbl level and the hope is that the combine will vote to go ahead despite forecasts of continuing low oil prices for an extended period.
Earlier this year, FAR announced its own resource estimate of 2C contingent resources at SNE of 641 million bbl.
BP lets contract for Tortue off Mauritania, Senegal
KBR Inc. will perform pre-front-end engineering design (FEED) work over the next 6 months in support of BP PLC in the optimization stage of the Tortue field development.
Partner to BP, Kosmos Energy Ltd. performed a drillstem test on the Tortue-1 in May, enabling the pre-FEED with a final investment decision in 2018 with production starting in 2021. Tortue is estimated to contain more than 15 tcf of gas.
KBR's new contracts include pre-FEED and project support covering design of the subsea, pre-treatment floating production, storage, and offloading (FPSO) facility, an inshore hub-terminal, and interfaces for floating liquefied natural gas (FLNG) for the Tortue project. According to KBR, the new work will build on the earlier concept phase work for development of the field already completed by KBR subsidiary Granherne for Kosmos.
The revenue from this contract is undisclosed and will be booked into backlog for KBR's engineering and construction business segment in the third quarter, the company said.
Drilling & Production — Quick TakesShell begins Gbaran-Ubie Phase 2 output
Shell Petroleum Development Co. of Nigeria Ltd. (SPDC) has started production at Gbaran-Ubie Phase 2 in Nigeria's Niger Delta region.
Phase 2 follows the first phase of the Gbaran-Ubie integrated oil and gas development, which was commissioned in June 2010. Peak production of 175,000 boe/d is expected in 2019, representing 864 MMscfd of gas and 26,000 b/d of condensate.
Eighteen wells have been drilled and a pipeline has been constructed between Kolo Creek and Soku, which connects the existing Gbaran-Ubie central processing facility to the Soku nonassociated gas plant. Gas first flowed from the wells in March 2016, with the facilities coming on stream in July.
SPDC is operator with 30% stake in a joint venture alongside government-owned Nigerian National Petroleum Corp. with 55%, Total E&P Nigeria Ltd. 10%, and Eni SPA subsidiary Nigerian Agip Oil Co. Ltd. 5%.
Lukoil starts South-West Gissar production
PJSC Lukoil said it has launched the main production and process facilities at the South-West Gissar project in southeastern Uzbekistan.
Facilities include a natural gas treatment plant with a rated capacity of 4.4 billion cu m/year, a gas pretreatment unit, and four gas-gathering stations. Gas production from 37 wells has reached 14 million cu m/day, or 5 billion cu m/year.
The license area includes seven fields. Lukoil said it produced 1.7 billion cu m of gas in 2016.
Lukoil entered the South-West Gissar project in 2008. The production sharing agreement with Uzbekistan is until 2043.
Cooper plans decommissioning of Basker-Manta wells
Cooper Energy Ltd., Adelaide, has engaged Perth engineering and design consultants Atteris Pty. Ltd. to undertake engineering studies for the decommissioning of Basker-Manta field's subsea oil wells and related systems in Bass Strait, offshore eastern Victoria.
The wells, which lie 56 km offshore, began oil production in 2005 but were suspended in 2010 and have not been producing since that time.
Basker field was discovered by Royal Dutch Shell PLC in 1983 and Manta in 1984, but the oil was not thought to be commercial until Anzon Energy developed a production system using a small floating production facility connected to a dedicated tanker that disconnected when loaded and sailed to southern Australian refineries. Gas produced with the oil was reinjected into the Basker reservoir.
Anzon ran into financial difficulties, and despite partnerships with Roc Oil Co. Ltd. and Beach Energy Ltd., the oil production wound down after 5 years, which at peak reached 6,000 b/d.
Cooper Energy bought into the fields in 2014 and now has 100% interest. The company is planning to redevelop Manta, Basker, and nearby Gummy fields predominantly as a gas project known as the Manta Gas Development.
At this stage the plan is to drill Manta-3 appraisal well in 2019. This well also will evaluate a new reservoir underneath the main target known as Manta Deep and use the results to inform a final investment decision for the gas project by the end of that year.
The project will dovetail with the company's proposed development of the nearby Sole gas field, which is slated to start gas production in March 2019. Production from Manta, if it goes ahead, is expected by 2021.
Both Sole and Manta projects will use the revamped onshore gas production facilities near Orbost, which is connected to the main Gippsland-Sydney gas trunkline.
PROCESSING — Quick TakesPreem advances Lysekil refinery expansion project
Swedish refiner Preem AB, a wholly owned subsidiary of Corral Petroleum Holdings AB, Stockholm, is progressing with its previously announced plan to expand vacuum distillation capacity at its 11.4-million tonne/year refinery at Lysekil, Sweden.
With delivery of the 37-m long tower that will form the heart of Lysekil's vacuum distillation unit (VDU) completed in mid-August, the refinery is scheduled to receive the VDU's furnance-the project's final piece of major equipment-in October, Preem said.
With a revised estimated cost of 1.6 billion kronor (Swedish) from its earlier 1.5-billion kronor price tag, the VDU expansion remains on schedule to be completed in 2018, the company said.
Granted environmental clearance to proceed from regional regulators in July 2016, the proposed project will add a second VDU to supplement the refinery's existing 64,600-b/d VDU to increase the plant's production of vacuum gas oil (VGO) and eliminate Preem's current monthly VGO import requirements of about 50,000 cu m.
The VDU expansion at Lysekil also will position the refinery to maximize its current crude through capacity as well as enable it to upgrade residual oil from other refineries in the region, Preem said.
Planned with a nameplate capacity to process 215-240 cu m/hr of residual oil, the VDU will increase the Lysekil refinery's VGO production capacity by about 50% from current production rates, according to official project documents.
In 2016, Preem let a contract to Amec Foster Wheeler to provide engineering, procurement, and construction management for the Lysekil VDU expansion
JV formed for proposed Barmer refining complex
Hindustan Petroleum Corp. Ltd. (HPCL) and the state government of Rajasthan have partnered to jointly develop HPCL's previously announced plan to set up a refinery and petrochemical complex in Barmer district, Rajasthan.
Officials from HPCL and Rajasthan's state government signed an agreement on Aug. 17 to form HPCL Rajasthan Refinery Ltd. (HRRL), a new joint venture company that will build and own the proposed project, according to a release from the office of Vasundhara Raje, Rajasthan's chief minister.
Signing of the agreement follows the Indian federal government's official approval of the 431.29 billion-rupee project on Aug. 16, Raje's office said.
The new JV comes as part of HPCL's revival of an earlier plan to build the 9 million-tonne/year integrated complex in Barmer, for which the parties signed a revised memorandum of understanding (MOU) in April.
While HPCL still will hold a 74% interest and the state government 26% in the HRRL JV as outlined under the original project, the renegotiated deal will cut Rajasthan state's total cost burden by about 400 billion rupees as well as increase its return on investment (ROI) to 12% vs. an earlier 2% ROI, according to the chief minister.
Scheduled to begin construction immediately following approval and clearance from India's Ministry of Environment, Forest, and Climate Change, the refinery will take about 4 years to complete for a targeted startup sometime in 2021-22.
The complex, which will use crude produced locally and elsewhere to produce Bharat Stage 6-grade-equivalent to Euro 6-quality-fuels, will be Rajasthan's first refinery as well as India's first petrochemical plant designed to process indigenous crude.
At the Apr. 18 signing of the revised MOU for the project, India's Minister of Petroleum and Natural Gas Shri Dharmendra Pradhan said Cairn India Ltd. will invest another 270 billion rupees during the next 4 years to increase oil production from its Barmer Block fields to help feed the refinery.
The tender process for the boundary wall of the 4,813-acre area on which the proposed refining complex will be built already is under way, according to Raje's office.
Falcon Oil lets contract for Pakistani refinery
Falcon Oil PLC, a subsidiary of Pakistani conglomerate Wak Group, Lahore, Punjab, has let a contract to China Energy Engineering Corp. subsidiary Guangdong Electrical Design Institute (GEDI) to build a grassroots deep-conversion refinery in Dera Ismail Khan, Khyber Pakhtunkhawa (KPK), Pakistan.
GEDI will provide engineering, procurement, and construction services for the refinery, which will have a nameplate crude processing capacity of 100,000 b/d, Wak Group said.
Without disclosing a definitive date for startup of the facility, Wak Group said GEDI is scheduled to complete its entire scope of work under the $3.58-billion EPC contract within 30 months from commencement.
In addition to its primary crude distillation unit, the proposed refinery will include a naphtha hydrotreater, a reformer, an isomerization unit, a thermal gas oil unit, an effluent treatment plant, and other unidentified auxiliary units, according to Falcon Oil's web site.
The refining complex also will be equipped with an independent 100-Mw electric power generation plant as well as access to 3.8 million tonnes of storage across Pakistan via more than 3,000-km of existing and planned crude and product pipelines.
Detailed information regarding proposed process technologies to be implemented at the refinery remains unavailable, but licensors Honeywell UOP LLC, Axens SA, and Albemarle Corp. all consulted on previously completed basic and front-end engineering design packages for the project, Falcon Oil said.
Part of Wak Group's plan to help meet Pakistan's rising demand for petroleum products as the country enters a new era of growth through development of the China Pakistan Economic Corridor, the refinery will process a slate of 90% imported crudes and 10% local KPK oil production into fuels meeting Pakistan's required Euro 2-quality specifications.
TRANSPORTATION — Quick TakesShell's Prelude FLNG vessel completes mooring
Royal Dutch Shell PLC has completed the mooring for its Prelude floating LNG (FLNG) vessel in the Browse basin offshore northwest Western Australia.
The 16 mooring chains had been positioned on the seabed prior to the vessel's arrival on location at the end of July. The chains were then lifted and secured to the FLNG facility. Shell says that the field hook-up and commissioning phase of the whole production system can now begin. This is expected to take 9-12 months to complete.
The Prelude FLNG vessel is 488 m long and 74 m wide. It will stay on location for 20-25 years and has been designed to withstand a category 5 cyclone.
Once on stream, the Prelude project will produce about 3.6 million tonnes/year of LNG.
Shell is operator of the development with a 67.5% interest. Partners in the project include Inpex 17.5%, Kogas 10%, and OPIC 5%.
AGL names preferred site for gas import terminal
Sydney-based gas and electricity provider AGL Energy has chosen Crib Point, near Hastings on Western Port Bay in southern Victoria, as its preferred site for a gas import jetty and pipeline.
Once the location of BP PLC's Western Port refinery, Crib Point is close to the ExxonMobil Corp.-BHP Billiton Ltd. gas and oil facilities at Long Island Point that are connected by pipeline to the combine's Longford processing plant in Gippsland and on into Victoria's gas distribution network.
AGL says Crib Point is the best-placed location to serve Victoria, which is Australia's largest gas market. It is also the best place to take advantage of the existing pipeline grid, industrial port facility, and associated systems.
AGL has been studying the economics and feasibility of an LNG import terminal in southeast Australia for several years as a means to ease the potential gas supply shortage in Australia's east coast gas market. The study includes the ability to buy gas either on a contract or spot price basis.
The $200-300 million (Aus.) concept includes a regasification terminal-either shore-based or possibly a floating storage and regasification unit-as well as connections into the gas supply pipeline grid. A final investment decision is expected in 2018 with construction beginning in 2019 for the terminal to be in operation in 2020-21.
The plan has already attracted interest from international gas suppliers as well as those within Australia.
AGL said it will continue to engage with relevant stakeholders, including government authorities and the Western Port community to complete its feasibility studies on the proposed site.
The naming of Crib Point accelerates the program as the company moves towards a formal application to the Victorian government.
