OGJ Newsletter

Nov. 14, 2016
International news for oil and gas professionals


Oklahoma issues directive after quake rocks Cushing

The Oil & Gas Conservation Division (OGCD) of the Oklahoma Corporation Commission (OCC) outlined a new directive in response to recent earthquake activity in Cushing on Nov. 6. The Oklahoma Geological Survey rated the earthquake as a magnitude 5.0.

Cushing is a natural gas hub and also features extensive crude oil storage. Gov. Mary Fallin declared a state of emergency for Payne County following the earthquake that damaged several buildings in downtown Cushing.

OGCD's plan covers 58 disposal wells that inject into the Arbuckle formation. Four of the disposal wells were shut after an OGCD directive in October 2015 so the total number of wells requiring action as of Nov. 8 was 54.

The directive, covering more than 700 sq miles, called for some injection wells to cease operations while operators of other wells were told to reduce injection volumes.

OGCD said 15 of the Arbuckle disposal wells included in the Nov. 8 directive already were shut in following a Sept. 3 directive.

The latest directive called for 7 more disposal wells to be shut-in and for operators of 16 disposal wells to reduce injection volumes 25% from the last 30-day average. This is in addition to 40% volume reductions imposed earlier this year.

"It is important to note that this plan is an initial response," OGDC said. "Operators are being warned that work is under way on a broader plan that will encompass a greater area and more Arbuckle disposal wells. Work is expected to take several weeks."

Magellan Midstream Partners said it temporarily shut pipeline and storage in the Cushing area as a precaution on the evening of Nov. 6. But inspectors found no damage so Magellan Midstream resumed normal operations Nov. 7.

Enbridge also initiated an emergency response plan to check tanks, pipes, motors, pumps, and other equipment.

Legislation on oil sands emissions filed

The minister responsible for the Alberta Climate Change Office has introduced legislation capping greenhouse gas emissions from oil sands work in accordance with the province's Climate Leadership Plan announced a year ago (OGJ Online, Nov. 23, 2015).

Environment and Parks Minister Shannon Phillips said the 100 megatonne/year limit "will drive innovation and reduce emissions per barrel while still allowing for production growth and development."

The oil sands industry now emits about 70 megatonnes/year of carbon dioxide-equivalent greenhouse gases.

The limit applies to in situ sites, mines, processing plants, primary production, enhanced recovery and experimental schemes, and buildings, equipment, structures, and vehicles associated with those sites.

Oil sands producers also will be subject to a $30/tonne carbon price.

As part of the climate plan announced last year, the provincial government will impose a $20/tonne carbon price across the economy next year and raise the price to $30/tonne in 2018.

The federal government recently said it will impose a carbon price reaching $50/tonne in 2022 in provinces with emission-reduction targets not matching its own (OGJ Online, Oct. 5, 2016).

Election removes a Lebanese licensing hurdle

Election by Lebanon's Parliament this week of Gen. Michael Aoun as president removes one of several hurdles to offshore oil and gas licensing by the financially and politically beleaguered country.

Progress toward licensing stalled in 2013 after the government enacted a petroleum law and made other preparations in response to giant gas discoveries in adjacent waters off Israel and Cyprus (OGJ Online, Sept. 12, 2016).

Formation of a fractious government took most of 2013 and part of 2014. The country hadn't had a president since May that year.

The presidential vacancy precluded action by the cabinet on two decrees needed to allow oil and gas licensing to advance. One would address a marine territorial dispute with Israel. The other would specify terms of exploration and production agreements.

Cabinet members are appointed by the president and prime minister and answer to Parliament. The cabinet has been unable to make substantial decisions.

The importance Aoun, former chief of the Lebanese Army, gives oil and gas licensing remains uncertain.

Because Aoun supports Iran and Hezbollah, the Islamic Republic's proxy in Lebanon, his election will complicate the territorial dispute with Israel.

Among the country's earlier licensing preparations was a prequalification round, which drew strong expressions of interest from international operators.

But the round occurred before the collapse in oil prices that began in 2014.

Exploration & DevelopmentQuick Takes

UKCS attracts frontier acreage bids in 29th round

The UK Oil & Gas Authority (OGA) has attracted 29 applications covering 113 blocks in 29th Frontier Licensing Round, which is the first in 2 decades to focus on underexplored, frontier areas of the UK Continental Shelf.

Applications were received from 24 companies and some of the proposed work programs include firm well commitments, OGA said. Areas on offer included the East Shetland Platform and the Rockall Trough and Mid-North Sea High areas that were the focus of the £20-million government-funded seismic acquisition program in 2015, which acquired 8,896 km of full-fold seismic in the Rockall Trough area and 10,849 km of full-fold seismic in the Mid-North High area (OGJ Online, July 28, 2016).

"Despite the difficult climate, industry has responded strongly to our offer," said Andy Samuel, OGA chief executive. He added that many of the applications were "high quality" and on blocks that had not attracted interest in recent licensing rounds, which could possibly confirm the high potential in the UKCS's frontier areas.

The 29th Offshore Licensing Round was launched on July 27 and closed for applications on Oct. 26. OGA said it is now commencing technical evaluation of the submissions and expects to award licenses as early as possible in 2017.

The UK 30th Offshore Licensing Round will cover mature areas of the shelf, OGA said, adding that some blocks on offer have not been available since the country's 3rd Licensing Round.

The UK government funded an additional 3D seismic acquisition in 2016 that focused on South West Britain and the East Shetland Platform. More than 13,500 km of new seismic data plus 20,000 km of reprocessed legacy seismic data is scheduled to be released to industry in second and third-quarter 2017.

Nova Scotia offshore blocks draw no bids

Nova Scotia received no bids for the six offshore blocks on offer for oil and gas licensing (OGJ Online, May 3, 2016).

Three of the blocks are in shallow water on the Scotian Shelf south of Sable Island, adjacent to existing natural gas production.

The other three blocks are to the south in deeper water.

The Canada-Nova Scotia Offshore Petroleum Board opened bidding last May.

It's accepting through Dec. 1 nominations for acreage to be included in the next call for bids next spring.

Drilling program commences offshore Tanzania

Royal Dutch Shell PLC and its partners Pavilion Energy Pte. Ltd. and Ophir Energy PLC have commenced a two-well drilling program on Blocks 1 and 4 offshore Tanzania in the Mafia Deep basin. The Noble Globe Trotter 2 is drilling both wells in 2,300 m of water.

The joint venture will invest close to $80 million into the drilling campaign, Shell said in its press release. Shell became the operator of the two blocks in Febraury 2016 after its combination with BG Group PLC (OGJ Online, Apr. 8, 2015). The wells will meet the remaining exploration requirements per the licenses issued by the Tanzanian Ministry of Energy Minerals (MEM).

The development of Blocks 1 and 4 is part of the Tanzania LNG project, which is a combined onshore LNG plant currently in the pre- front-end engineering and design stage.

Ophir was awarded 100% interest in Block 1 in 2005, and in Blocks 3 and 4 in 2006. The operator has drilled 11 exploration wells and 5 appraisal wells on a mix of Tertiary and Creataceous plays since 2010. Block 1 is home to the Mzia and Jodari discoveries (OGJ Online, Aug. 27, 2014, May 1, 2013). Blocks 1 and 4 contain 17 tcf of gross contingent resources.

Ophir farmed out 60% of Blocks 1 and 4 to BG, now Shell, in 2010, and sold a further 20% to Pavilion Energy in 2014 for $1.3 billion. Ophir retains 20% interest in Blocks 1 and 4.

India claims $1.55 billion for gas migration

Partners in the deepwater KG-D6 block off the southeast coast of India say the Indian government is seeking about $1.55 billion for natural gas said to have migrated from neighboring blocks.

Reliance Industries Ltd., BP PLC, and Niko Resources Ltd. received a communication from India's Ministry of Petroleum and Natural Gas late last week. RIL has 60% in the block, BP 30%, and Niko 10%.

Reliance, the operator, said it has worked within the boundaries of the KG-D6 block and has complied with all applicable regulations and provisions of the production-sharing contract (OGJ Online, July 1, 2013).

RIL said the claim by the government "is based on misreading and misinterpretation of key elements of the PSC" and is without precedent in the industry. The company proposes to invoke the dispute resolution mechanism in the PSC and issue a notice of arbitration to the government.

Niko said it believes the group is not liable for the amount claimed by the government of India.

Drilling & ProductionQuick Takes

Total inks deal to aid South Pars field development

Total SA has signed a preliminary agreement to help develop the massive South Pars natural gas field offshore Iran. The pending transaction marked the first Western energy investment in Iran since international sanctions were lifted earlier this year.

Terms call for Total, China National Petroleum Corp., and Iran's state-owned Petropars to develop the South Pars Phase 11 (SP11) project, which will have a production capacity of 1.8 bcfd. The produced gas will be fed into Iran's gas network. Iranian government officials expect the deal to be finalized in 9 months.

Total will operate the project with 50.1% interest. CNPC will take 30% interest. Petropars will hold the rest. Total said it will avoid US sanctions on Iran by using its euro-denominated cash to finance the deal.

Initial plans call for the SP11 project to be developed in two phases. The first phase, with an estimated cost of $2 billion, will consist of 30 wells and 2 wellhead platforms connected to existing onshore treatment facilities by 2 subsea pipelines.

"Following Total's successful development of Phases 2 and 3 of South Pars in the 2000s, the group is back to Iran to develop and produce another phase of this giant gas field," said Patrick Pouyanne, Total chairman and chief executive officer.

"Total will develop the project in strict compliance with national and international laws," he said.

"This project fits with the group's strategy of expanding its presence in the Middle East."

Terms call for project partners will conduct exclusive negotiations to finalize a 20-year contract within the framework of Iranian Petroleum Contract recently approved by the Iranian Parliament.

In parallel, Total will launch engineering studies and a call for tender process so that construction contracts can be awarded immediately upon signature of the final agreement.

Chevron begins gas production from Alder field

Chevron North Sea Ltd. has started production from the Alder high-pressure, high-temperature (HPHT) natural gas-condensate field 160 km from the Scottish coastline in the central North Sea.

Alder, which lies in 150 m of water, is a single subsea well tied back via a 28-km pipeline to the existing ConocoPhillips-operated Britannia bridge-linked platform (BLP), in which Chevron holds 32.38% nonoperated working interest. The project has a planned design capacity of 110 MMcfd of gas and 14,000 b/d of condensate. Chevron expects output from the field to ramp up over the coming months.

Produced fluids are processed at a dedicated module attached to the Britannia BLP. Alder condensate will be exported via the Forties pipeline system to the Grangemouth terminal and gas exported to the Scottish area gas evacuation terminal at St. Fergus near Peterhead, Scotland.

Development of Alder has been enabled through the application of subsea technologies designed to meet the temperature and pressure challenges of the field. Key technologies have included a number of firsts for Chevron in the North Sea, including a vertical monobore subsea tree system, subsea high-integrity pressure protection system (HIPPS), and specially designed corrosion monitoring system to measure the real-time condition of the production pipeline.

Discovered in 1975, Alder field is operated by Chevron North Sea with 73.7 interest. ConocoPhillips (UK) Ltd. holds the remaining 26.3%.

In the UK, Chevron North Sea has working interests in 10 offshore producing fields, including three operated fields (Alba, 23.4%; Captain, 85%; and Erskine, 50%) and seven nonoperated fields (Britannia, 32.4%; Brodgar, 25%; Callanish, 16.5%; Clair, 19.4%; Elgin-Franklin, 3.9%; Enochdhu, 50%; and Jade, 19.9%).

The Chevron unit's net production in 2015 from these fields averaged 40,000 b/d of liquids and 115 MMcfd of gas.

Lukoil starts oil production from Filanovsky field

PJSC Lukoil has started commercial oil production from Vladimir Filanovsky field in the Caspian Sea off Russia.

Two horizontal wells are producing a total of more than 45,000 b/d, and a third production well is being drilled.

The field is about 220 km from the city of Astrakhan. Water depth ranges 7-11 m.

Lukoil discovered the field in 2005 (OGJ Online, Jan. 26, 2006). First-stage development has included construction of an ice-resistant stationary platform, a living quarters platform, the central treatment platform, the riser unit, onshore storage facilities, and subsea and onshore pipelines.

The second stage of field development is under way, including a second ice-resistant platform and a living quarters platform (OGJ Online, Dec. 20, 2013).

Filanovsky infrastructure is also used for transportation of hydrocarbons from Yuri Korchagin field, which was commissioned in 2010.


CNOOC-Shell JV advances Huizhou ethylene expansion

Royal Dutch Shell PLC subsidiary Shell Nanhai BV and China National Offshore Oil Corp.'s (CNOOC) 50-50 joint venture CNOOC & Shell Petrochemicals Co. Ltd. (CSPC) has completed its previously announced plan to take ownership of CNOOC's ongoing project to build a 1.2 million-tonne/year ethylene cracker and associated derivatives units at CSPC's existing petrochemical complex in the Daya Bay Economic & Technological Development Zone, Huizhou, Guangdong Province, China (OGJ Online, Dec. 15, 2015).

CSPC assumed full ownership of the project as of Nov. 2 after receiving all necessary government approvals, Shell and CNOOC said.

With construction work on the expansion now 70% completed, the project's new units-including what will be China's largest styrene monomer and propylene oxide (SMPO) plant-are due for startup sometime during fourth-quarter 2017, the companies said.

The project, on which Shell and CNOOC reached final investment decision in March, comes as part of CSPC's strategy to help meet China's growing domestic demand for petrochemical products (OGJ Online, Mar. 22, 2016).

Alongside its increased production of ethylene, the expanded complex will use Shell's proprietary OMEGA, SMPO, and Polyols technologies to produce the following: ethylene oxide, 150,000 tpy; ethylene glycol, 480,000 tpy; styrene monomer, 630,000 tpy; propylene oxide, 300,000 tpy; and high-quality polyols, 600,000 tpy.

Pakistani refiner advances expansion, upgrades

Attock Refinery Ltd. (ARL) has expanded a captive power plant as part of an ongoing $251-million upgrading project under way at the operator's 43,000-b/d refinery at Morgah, northeast of Rawalpindi, Pakistan.

MAN Diesel & Turbo SE, Augsburg, Germany, and Hyundai Engineering Co. Ltd., Seoul, have completed an 18-Mw expansion of the refinery's previous 7.5-Mw captive power plant to its new 25.5-Mw capacity using three MAN 14V32/40 gensets, MAN Diesel & Turbo said.

Powered by heavy fuel oil for production and supply of electricity for the refinery, the power plant expansion is designed to accommodate energy requirements for a series of new units to be added under the upgrading program.

Alongside the power plant expansion, ARL's modernization and upgrading project includes the following unit additions:

• A 10,400-b/d preflash unit at one of the refinery's existing crude distillation units to enable increased processing of rising crude production from Pakistan's North Region and lift overall crude capacity at the site to 53,400 b/d.

• A 7,000-b/d naphtha isomerization unit to increase the volume as well as improve the quality of the refinery's gasoline production by lowering levels of benzene and aromatics to below current Euro 2-quality specifications.

• A 12,500-b/d diesel hydrodesulfurization (DHDS) unit to reduce the sulfur content of diesel production at the plant to 500 ppm in compliance with Euro 2-quality specifications.

Previously due to be in operation by June 2016,

The upgrading program's individual unit projects-all of which were to be operable by June 2016-are in the process of sequential startup, with the DHDS unit already formally commissioned in July, ARL said in its latest quarterly report to investors dated Oct. 19.

While ARL confirmed commissioning activities currently are under way at the new isomerization unit, the company did not disclose firm timelines for when that unit or the preflash unit would reach full startup.

ADNOC, Oxy JV to expand Al Hosn sour gas plant

A joint venture of Abu Dhabi National Oil Co. and Occidental Petroleum Corp. plans to expand by 50% the capacity of the Al Hosn sour gas plant.

The plant is at the Shah sour gas-condensate onshore field, southwest of Abu Dhabi City, UAE.

Al Hosn began operating in 2015 and has reached full capacity of 1 bcfd. The $10-billion plant started operations earlier this year.

In today's announcement, the companies did not release a cost estimate or timetable. But the expansion could become operational within the life span of ADNOC's new 5-year business plan, which is part of the company's 2030 Strategy.

"A key element of our 2030 strategy is to ensure we produce sufficient gas to meet our steadily increasing requirement for gas, and match rising demand from our international customers," said Sultan Al Jaber, UAE minister of state and chief executive officer of ADNOC Group. "Sour gas will play an important role in ensuring we deliver on those commitments."

Vicki A. Hollub, Oxy president and chief executive officer, said, "Demand for domestic gas is rising and processing additional sour gas from new and existing reservoirs makes sound business sense."

Al Hosn produces 500 MMcfd of network gas, 4,400 tons/day of natural gas liquids, 33,000 b/d of condensates, and about 9,000 tons/day of granulated sulfur. ADNOC has a 60% share in the Al Hosn joint venture and Oxy has 40%.


Canada okays $1.3-billion TransCanada NGTL revamp

TransCanada Corp. reported that the Canadian government has given the go-ahead on the pipeline operator's $1.3-billion NGTL System expansion project, which includes five pipeline sections totaling 230 km and the addition of two compression facilities.

The first facilities are expected to enter into service in second-quarter 2017, with the entire project expected to be completed by second-quarter 2018.

Russ Girling, TransCanada's president and chief executive officer, said the expansion of the NGTL System is a key component of the company's $25-billion near-term capital spending program.

The project will require the purchase of $1.2 billion in Canadian goods and services, including $800 million in labor income during construction.

Currently the NGTL System gathers 75% of natural gas production from the Western Canadian Sedimentary Basin. So far in 2016, NGTL's average transported volume is 11.3 billion bcfd compared with 2015's average of 11 bcfd.

Dominion Midstream to buy Questar Pipeline

Dominion Midstream Partners LP has agreed to acquire Questar Pipeline LLC from Dominion Resources Inc. for $1.725 billion including debt. The deal has an anticipated effective date of Dec. 1.

Questar has 27,500 miles of nautral gas distribution pipeline, 3,400 miles of gas transmission pipeline, and 56 bcf of working gas storage in Colorado, Utah, and Wyoming.

"Dominion Midstream's planned acquisition of Questar Pipeline and related financing have been anticipated as part of the financing structure of the Dominion-Questar Corporation combination since it was announced in February 2016," explained Thomas F. Farrell II, chairman, president, and chief executive officer of Dominion and chairman and chief executive officer of Dominion Midstream.

The $4.4-billion Dominion Resources and Questar merger closed in September.

"The capital generated from the Questar Pipeline dropdown will allow Dominion to pay down debt while supporting its earnings and dividend growth targets," Farrell said.