OGJ Newsletter

July 24, 2017
International news for oil and gas professionals


Shell chief sees many energy transitions

Royal Dutch Shell PLC will invest $1 billion/year on its New Energies division by the end of the decade as part of a global energy transition often misrepresented as a revolution, according to the company's chief executive officer.

"In truth, different countries and different sectors will advance at different speeds," Ben Van Beurden told the World Petroleum Congress in Istanbul. "In truth, we are not talking about a moment in time but of change that will take place over generations."

Adapting to climate change, he said, a European country must "renew and evolve its infrastructure to be much cleaner and achieve great efficiencies-to bring down the amount of energy used per capita and to cut the emissions associated with that consumption."

In contrast, a different country starting with minimal infrastructure, limited financial resources, and rapid population growth "will have an entirely different task," he said.

"So there is not one, single energy transition under way but many, all running alongside each other," Van Beurden said. "These are happening right now, but they will take many decades to play out."

The Shell chief said markets and competition should find the many solutions required to address the many challenges of meeting energy needs while lowering emissions of greenhouse gases.

"Some of that will involve well-targeted regulation to mandate things such as efficiency improvements," he said. "Part of it will mean consumer incentives to pull people into new habits and behaviors.

"Other initiatives, like that of the Taskforce on Climate-related Financial Disclosures, can play their part." Shell, he said, had joined that initiative 2 weeks earlier.

Van Beurden also supported government-led carbon-pricing mechanisms, which he said are needed for technologies such as carbon capture and storage.

"Until there is a market for carbon," he said, "the economic justification for such facilities is hard to make."

India reported to be considering mergers

The Indian government is reported to be considering mergers of state-owned oil and gas companies to create two integrated giants.

Official discussion about consolidation of some or all of India's oil and gas "public-sector undertakings" (PSUs) surfaced earlier this year in government budget presentations.

Since then, the cabinet has been reported to be preparing to sell the state share of refiner-marketer Hindustan Petroleum Corp. Ltd. to Oil & Natural Gas Corp., the largest upstream PSU.

HPCL operates a 130,000-b/d refinery in Mumbai and a 167,000-b/d refinery at Visakhapatnam. It also is a partner in a 181,000-b/d joint-venture refinery at Bathinda.

More recently, discussion has begun of a merger of Oil India Ltd., the country's second-largest upstream PSU, and Indian Oil Corp. Ltd., the largest state-owned refiner-marketer.

IOCL controls 1.6 million b/d of distillation capacity in nine refineries and two refineries operated by subsidiaries.

There has been no official confirmation of the possible OIL-IOCL merger.

Trump to nominate McIntyre as FERC member, chairman

US President Donald Trump intends to nominate Kevin J. McIntyre, co-leader of the global energy practice at Jones Day in Washington, as a member and, ultimately, chairman of the Federal Energy Regulatory Commission.

McIntyre's practice at Jones Day has focused primarily on governmental regulation of energy markets, electric and natural gas utilities, and oil and gas pipelines, according to the law firm.

The July 13 announcement followed one 2 weeks earlier that Trump would nominate Richard Glick, presently general counsel for the US Senate Energy and Natural Resources Committee, as a FERC member.

The US Senate Energy and Natural Resources Committee voted earlier in June to refer the nominations of Neil Chatterjee and Robert Powelson as FERC commissioners to the full Senate for final approval.

Exploration & DevelopmentQuick Takes

ExxonMobil, Statoil to operate blocks off Suriname

An ExxonMobil Corp.-led group and Statoil ASA have been chosen to respectively operate two blocks offshore Suriname.

ExxonMobil Exploration & Production Suriname BV, along with partners Statoil and Hess Corp., have signed a production-sharing contract with Suriname's state-owned Staatsolie Maatschappij Suriname NV for the 11,500-sq-km deepwater Block 59. ExxonMobil will serve as operator.

Block 59 is 305 km offshore Paramaribo in 2,000-3,600 m of water. It shares a maritime border with Guyana, where ExxonMobil is operator of three offshore blocks, including the one that holds Liza field, where the firm last month made a final investment decision on the first phase of development.

Block 59 also is next to Suriname's Block 42, where Hess, a Liza partner with ExxonMobil, already has 33.3% interest and Kosmos Energy Ltd. is operator.

Block 59 partners are preparing to begin exploration activities, including acquisition and analysis of seismic data. ExxonMobil, Hess, and Statoil each hold a third of the block's interest.

Statoil separately signed a PSC with Staatsolie for the 6,200-sq-km Block 60. It lies 250 km offshore in 800-1,900 m of water and is next to Suriname's Block 54, where Statoil already has 50% interest and Tullow Oil PLC is operator. Block 54 is the site of the Araku prospect on which drilling is planned for this year's second half. The prospect is a large structural trap that has an estimated resource potential of 500 million bbl of oil.

ExxonMobil pulls out of East Natuna development

ExxonMobil Corp. has decided to walk away from development of the East Natuna natural gas permit in Indonesia saying it no longer wishes to continue discussions or activity on the block.

The major's decision comes in the wake of a comprehensive technology and marketing review that concluded the block is uneconomical for the company under the current terms. Despite the withdrawal, ExxonMobil is reported to have offered to help with technology and technical assistance for the development project if needed.

East Natuna, first discovered by Italian company Agip in 1973, holds an estimated 46 tcf of recoverable gas in a Miocene reservoir and is one of the world's largest untapped gas fields.

However, ongoing difficulties for development include remoteness of the block, which lies in the Greater Sarawak basin 225 km northeast of the Natuna Islands off Borneo and 1,100 km north of Jakarta, as well as the fact that the gas has a carbon dioxide content of 70%.

There have also been a series of contract disputes over the years. Indonesian state company Pertamina and ExxonMobil first formed a partnership at the field in 1980. Several agreements were signed and then terminated earlier in the 2000s including a deal between Pertamina, ExxonMobil, French company Total SA, and Malaysian state firm Petronas in 2011. Petronas and Total subsequently pulled out of the field and Thai company PTTEP joined Pertamina and ExxonMobil hoping to sign a production-sharing contract in 2016. This was not consummated either.

Development costs for the field, which lies in 145 m of water, are estimated to be as much as $40 billion.

Pertamina and the Indonesian government are still keen to develop East Natuna and the government is reported to be considering a special incentive to improve the economics and bring ExxonMobil back to the negotiating table.

BOEM approves Eni's Beaufort Sea exploration plan

The US Bureau of Ocean Energy Management conditionally approved a Beaufort Sea exploration plan it received from Eni US Operating Co., a subsidiary of Italian multinational oil and gas company Eni SPA, for the drilling of four exploration wells in federal submerged lands from its preexisting Spy Island drill site in Alaskan state waters starting in December, the US Department of the Interior agency said on July 12.

"Eni brought to us a solid, well-considered plan," said Walter B. Cruickshank, BOEM acting director.

Drilling will take place only during the winter months, BOEM noted. Its evaluation of the exploration plan during the past 30 days included a site-specific environmental assessment (EA) of the proposed exploration activities under the National Environmental Policy Act. The EA concluded with a finding of no significant impact, BOEM said.

The evaluation also included two separate public comment periods: one to give the public the opportunity to provide information on issues that should be examined in the EA, and one to comment on the exploration plan (EP) itself, it said.

Blocks awarded in UK supplementary offshore round

The UK Oil & Gas Authority (OGA) has reported offering for award 12 licenses to 10 companies in the 2016 Supplementary Offshore Licensing Round, which closed for applications in March.

There were 14 blocks originally on offer in this latest round, which was in response to industry nominations of areas outside of those covered by last year's Frontier 29th Licensing Round.

Locations varied across the UK Continental Shelf (UKCS) from the southern North Sea to East of Shetland. The round offered blocks under flexible terms, enabling applicants to define a license duration and phasing that will allow them to execute their optimal work program.

In total, 15 applications covering 11 blocks were received. OGA is now ready to make offers of award in respect of 12 licenses covering the 11 blocks.

Five of the awards are for work programs that will proceed straight to second term, or potential developments or redevelopments of fields where production had ceased and the acreage had been relinquished. The remainder of the licenses will enter the initial term, or exploration stage.

OGA CEO Andy Samuel said, "The strong interest in this round bodes well for the forthcoming 30th round, demonstrating the renewed attractiveness of the UKCS and the opportunity for operators to rebuild their portfolios with a mixture of exploration, development, and redevelopment activity."

Iranian firms sign field-development MOUs

Two state-owned oil firms in Iran have signed separate memoranda of understanding with international counterparts covering field development in the Islamic Republic.

National Iranian Oil Co. signed an MOU with a consortium including Toyo Engineering Corp., Chiba, Japan, covering revamp of facilities and the upgrade of production of natural gas at offshore Salman oil and gas field. The group also includes Iran's Petropars. The partners will finance studies of the rehabilitation project. If they decide to proceed, the deal with be an engineering, procurement, construction, and finance contract financed by Toyo.

Salman field, once known as Sassan, straddles Iran's maritime boundary with Abu Dhabi. Recent estimates peg Iran's Salman production at 40,000 b/d. Abu Dhabi produces 70,000 b/d from separately developed Abu Al Bukhoosh field.

Under the other MOU, National Iranian South Oilfields Co. and Zarubezhneft, Moscow, will assess development of Shadegan and Rag-e Sefid oil fields in southern Iran. Both are giant oil fields discovered in the 1960s. The Russian firm will study the fields and submit a development proposal within 9 months.

Last November, NISOC signed an MOU with Schlumberger for formation studies at those fields and nearby Parsi field.

Drilling & ProductionQuick Takes

Oil Search, High Arctic form JV for PNG drilling

Oil Search Ltd. and Calgary-based High Arctic Energy Services Inc. have entered into exclusive negotiations to form a joint venture company for work in Papua New Guinea.

The deal revolves around High Arctic exchanging an equal share of three of its owned rigs-102, 115, and 116-for an equal share of two rigs-103 and 104-that it has historically managed for Oil Search under long-term management agreements. The rigs are to be put into a jointly owned company that has yet to be given a name.

High Arctic will provide the management of the joint company, which will focus exclusively on rig ownership.

The rigs, mainly in the Papua New Guinea highlands, are of modern design and are able to be transported by helicopter.

As part of the proposed arrangement, High Arctic will operate the rigs under a minimum 3-year exclusive call rig services agreement. High Arctic says first-year rates under the new rig services contract are likely to be 20-23% less than under the previous contract.

High Arctic's rental equipment business-the provision of rig mats, camps, and drilling support equipment to all its customers including the proposed combine-will continue to be owned by High Arctic and will not be part of the proposed transaction.

Negotiations surrounding details of the JV deal are expected to be completed by yearend. Meanwhile, the current contracts for operation of Rigs 103 and 104 will be extended for 1 year at the new rates.

Mike Maguire, High Arctic president, international, said the JV will be an innovative way of meeting Oil Search's chief concern of reducing well costs and providing cost-efficient drilling in Papua New Guinea, which is High Arctic's largest region of operation.

Shell to buy FPSO serving Stones project

Shell E&P Offshore Services BV exercised its right under a charter agreement to buy the Turritella floating production, storage, and offloading vessel from SBM Offshore NV.

The $1-billion transaction allows Shell to assume operatorship of the offshore Stones development in its entirety. Turritella is the second FPSO to operate in the Gulf of Mexico. The transaction is expected to close in early 2018.

The Stones development is in 9,500 ft of water some 200 miles offshore Louisiana in the Walker Ridge area. The Turritella FPSO has a turret with a disconnectable buoy allowing it to weathervane in normal conditions and to disconnect before the approach of a hurricane.

The firm selling the asset is a joint-venture owned by SBM Offshore with 55% interest, Mitsubishi Corp. with 30% interest, and Nippon Yusen Kabushiki Kaisha with 15% interest.

Ichthys field's FPSO vessel sets sail

The Ichthys Venturer floating production, storage, and offloading vessel has left Daewoo Shipbuilding & Marine Engineering's shipyard in South Korea and is stationed about 30 km southeast undergoing final preparations for sailing to Western Australia.

Construction of the vessel is complete and it is running through some commissioning activities and final checks before it begins the 6,000-km tow south to its final Browse basin location in Ichthys field off northwest Western Australia.

The FPSO will be permanently moored 3½ km from the Ichthys project's central processing facility, Ichthys Explorer, which is already anchored on station.

The Venturer, with a capacity to hold 1 million bbl, will receive the condensate sent from the Explorer and load it onto tankers for direct export.

Final hook-up and commissioning of the production and delivery system will take place once the FPSO arrives.

The offshore component of the Ichthys LNG project comprises the CPF and FPSO moored close to the field 220 km off the Kimberley coast of Western Australia plus an 890-km subsea pipeline that will take gas to the 8.9 million-tonnes/year onshore LNG plant in Darwin.

The Ichthys project is expected to come on stream at the end of the first quarter next year.


OMV Petrom starts work on unit at Petrobrazi facility

OMV Petrom SA, Bucharest, has started construction of a grassroots unit that will convert LPG components into Euro 5-quality gasoline and middle distillates at its 4.5-million tonne/year Petrobrazi refinery in the southeast region of Romania.

First-phase construction, which began on July 19, will involve pouring about 3,000 cu m of concrete and laying 335 tonnes of steel for the Polyfuel unit's foundation.

The 200,000-tpy unit, which will be based on the first commercial use of Axen SA's proprietary PolyFuel technology, will enable the refinery to shift as much as 50,000 tonnes of its current production of LPG components into higher-quality gasoline and middle distillates using a catalytic process.

Specifically, the unit will consist of three main reactors, several adsorbers, as well as columns and pumps, working together to convert LPGs and light-cracked naphtha from the refinery's fluid catalytic cracking unit into diesel.

The company did not disclose a detailed timeline for construction activities, but Neil Anthony Morgan, OMV Petrom's executive board member responsible for downstream operations, said the €60-million project remains on schedule to be fully commissioned in early 2019.

Since its privatization in 2005, OMV Petrom has invested about €1.2 billion in the Petrobrazi refinery, €600 million of which covered costs for the 2010-14 modernization program that involved upgrading, expanding, and replacing multiple installations at the refinery, including the gas oil hydrotreater, fluid catalytic cracker, coker, crude vacuum distillation unit, gas desulfurization and sulfur recovery unit, hydrogen plant, and refinery tank farms.

Linn unit changes name, builds Merge gas plant

Linn Midstream LLC, a wholly owned subsidiary of Houston-based Linn Energy Inc., has been renamed Blue Mountain Midstream LLC and agreed with BCCK Engineering Inc. to build the 225-MMcfd Chisholm Trail cryogenic gas plant in the Merge play of central Oklahoma.

Construction on the plant is under way and it's expected to be commissioned during second-quarter 2018. Linn acreage recently contributed to its Roan Resources LLC upstream joint venture with Citizen Energy II LLC remains dedicated to Blue Mountain's Chisholm Trail midstream business.

Roan's 140,000 total net acres will be largely contiguous in Canadian, Carter, Cleveland, Garvin, Grady, Kingfisher, McClain, and Stephens counties of Oklahoma.

Combined production on the acreage averaged more than 20,000 boe/d as of May and, at current rig pace, is forecast to have an exit rate of more than 40,000 boe/d by yearend, with additional growth expected as drilling increases.

Chisholm Trail is in the heart of the liquids-rich Merge-SCOOP-STACK and has 30 miles of existing gas gathering pipeline and 60 MMcfd of refrigeration capacity. Infrastructure expansions are under way to add 35 miles of low-pressure gathering and increase compression throughputs.


ESAI: New pipelines to feed USGC surplus

Pipeline capacity due online soon will aggravate a surplus of light crude oil on the US Gulf Coast (USGC), suppressing prices and straining export capacity, predicts ESAI Energy LLC.

According to the firm's North America Watch, 730,000 b/d of new pipeline capacity will have come online between the Permian basin and the USGC by yearend. And by 2019, planned capacity of about 840,000 b/d will be online to carry Permian oil to Corpus Christi.

ESAI expects Permian basin production of light oil to increase by 460,000 b/d this year and by 340,000 b/d in 2018.

"Although we see that the USGC surplus could rise to 2 million b/d next year, its disposition is unclear," said Elisabeth Murphy, an ESAI Energy analyst. "Lower prices will adversely impact the rate of growth coming from shale production."

The ability of USGC refiners to increase runs has limits, ESAI notes.

Exports will rise, but the rate will depend on availability of dock and loading space as crude exports compete with product exports.

Another export constraint is the ability of foreign demand for light crude to absorb the US surplus, the firm says.

Its report cites the expansion of transport capacity under way in Houston, Beaumont-Port Arthur, and Corpus Christi in anticipation of growing arrivals of crude from the Permian basin.

Germany's first LNG import terminal to be studied

Gasunie LNG Holding BV, Oiltanking GMBH, and Vopak LNG Holding BV have received approval under the European Union Merger Regulation to establish a joint venture for owning and operating a 2-3 million tonne/year LNG terminal in northern Germany.

The import terminal would be Germany's first.

The three companies are investigating the possibility of building and operating a multiservice LNG terminal, including import and small-scale services, at Brunsbuttel along the Elbe River close to the city of Hamburg. Germany can now receive regasified LNG from either Fluxys' Zeebrugge LNG terminal in Belgium, with 9-billion cu m/year sendout capacity, or the 12-billion cm/year sendout Gate LNG terminal owned by Gasunie and Vopak in the Netherlands.

The feasibility study consists of economic, technical, nautical, and regulatory assessments, as well as the permitting procedures. No investment decisions have been taken yet.

E.On AG in 2006 proposed a 7.75-million tpy terminal at Wilhelmshaven, Lower Saxony, but this project has not advanced.