OGJ Newsletter

Oct. 30, 2017
International news for oil and gas professionals


ESAI: Price hikes to cut Saudi oil demand

Price increases accompanying economic reform will lower demand for gasoline in diesel again next year in Saudi Arabia, predicts ESAI Energy LLC, Boston.

According to the firm's Middle East Watch Products report, the Saudi government is expected to raise product prices as soon as next month. Until crude oil prices slumped in 2014, oil demand had been growing rapidly in Saudi Arabia and other Middle Eastern oil-producing countries. Saudi Arabia has begun a sweeping program aimed at lowering consumer subsidies and its economy's dependence on oil sales.

According to ESAI, the imminent changes will raise the price of gasoline to 36¢/l. from 20¢/l. and of diesel to 24¢/l. from 12¢/l. The firm expects the price hikes to trim Saudi demand for gasoline by about 20,000 b/d next year to 580,000 b/d and for diesel by 40,000 b/d to 550,000 b/d.

"The Saudi government wants to bring fuel prices to parity with international market prices by 2020," says ESAI Energy Analyst Amrit Naresh, noting that the November increases will nudge the Saudi gasoline price to 70% of international parity and the diesel price to 50% of the global marker.

"We expect further price hikes in the coming years," he says.

In all Gulf Cooperation Council countries, Naresh adds, a value-added tax system due in place next year will accommodate further tax hikes that will increase consumer prices and suppress growth in fuel demand.

US Senate rejects ANWR amendment from budget bill

The US Senate rejected an amendment that would have removed language authorizing oil and gas development within the Arctic National Wildlife Refuge from the fiscal 2018 budget bill on Oct. 19. The 52-48 balloting largely followed party lines, with Republicans except Susan Collins (Me.) voting against it and Democrats except Joe Manchin (W.Va.) supporting it.

The amendment's main sponsor, Maria E. Cantwell (D-Wash.), the Energy and Natural Resources Committee's ranking minority member, argued that more than 60 years' protection of one of the most pristine areas in the US should not be sacrificed for crude oil that the nation probably does not need.

"We have had record oil production in the last 10 years-a 77% increase. The oil we would get from it we wouldn't get until 10 years from now, and it would supply oil for only 1 year in the US. It is not worth it," she said.

Committee Chair Lisa Murkowski (R-Alas.) noted that expanding energy production in federally controlled areas helps the US reduce its budget deficit, builds new wealth, strengthens national security, and makes the country more competitive.

"We can and we must do more as a nation to responsibly develop our resources, our energy resources providing economic security, energy security, and national security," Murkowski said. "The Energy Committee is prepared to meet this instruction to raise a billion dollars over the next decade."

Pa. House GOP leaders urged to consider severance tax

Pennsylvania Gov. Tom Wolf (D) called on Pennsylvania House Republican leaders to consider imposing a severance tax on unconventional natural gas production. "It is well past time for [them] to allow a vote on a commonsense severance tax that will make oil and gas companies finally pay their fair share," he said on Oct. 24.

A majority of Pennsylvanians support such a tax, along with many Republicans and Democrats in the House and Senate, Wolf said. "Pennsylvania should no longer be the only gas-producing state in the country without one. I am calling on the House to hold a vote on a severance tax this week," he said.

Rep. Gene DiGirolamo (R-Bucks County) introduced HB 1401 on May 18 with 23 cosponsors. The House's Finance Committee reported an amended version out on Oct. 18. Oil and gas associations in the state expressed their criticisms most recently in July.

"It's true, the gas may be here, but it is also in many other states where the tax, business, and regulatory climate-even in those states with severance taxes-is more amenable to economic development," Pennsylvania Independent Oil & Gas Association Pres. Daniel J. Weaver said. "Pennsylvania would lose out on new investment and our industry will not succeed as the governor claims he wants."

Exploration & DevelopmentQuick Takes

Po Valley to revive historic Eni gas field

Po Valley Energy Ltd., Perth, is planning to revive Eni SPA's former Selva gas field in northern Italy with the drilling of the Podere Maiar-1 well within the Podere Gallina permit near Bologna in mid-November.

The plan is to target specific depths across several thick Pliocene gas zones in the field. Po Valley says particular focus will be on a stratigraphic prospect at a target depth of 1,300 m.

Po Valley Chairman Michael Masterman explained that the company has identified an undrained area, named Selva Stratigraphic, updip of the existing historic wells. A second exploration target, East Selva, also has been delineated on the pinch out edge to the east of the main field.

Under Eni's operation Selva field historically produced 83 bcf of gas from 15 wells over 35 years.

Po Valley now has an 80% interest in both Selva field and the prospective nearby Selva East prospect. The other 20% interest is held by United Oil & Gas.

Masterman said Podere Maiar-1 is a strategic priority for the company that has potential to add more gas production to its portfolio in Italy.

The new program is in addition to Po Valley's wider corporate restructuring moves this year within Europe's energy market. Earlier this month the company entered into a nonbinding conditional agreement with Sound Energy and Saffron Energy. The proposed restructure centers on Po Valley's majority 54% interest in Saffron which will become the three-way host vehicle for Saffron's Italian assets as well as three new Italian assets owned by Po Valley and three gas exploration wells and two gas production assets owned by Sound Energy.

The restructure is subject to regulatory and shareholder approvals but is expected to be complete early in 2018. All being well, Po Valley will emerge with a 51% interest in the enlarged Saffron Energy. Saffron shareholders will have 16% and Sound Energy shareholders will have 33% in the new entity which will eventually be renamed Coro Energy.

AWE completes flow test of Waitsia-3 appraisal well

The AWE Ltd.-led joint venture in the onshore north Perth basin in Western Australia has conducted a successful flow test of its Waitsia-3 appraisal well.

Well clean-up began on Oct. 18 and the following day the company recorded a gas flow at an instantaneous maximum rate of 50 MMcfd and an average of 49.5 MMcfd on an 80/64-in. choke. Flowing wellhead pressure was measured at 1,929 psi during a 2½-hr period.

The well is now being shut in for a brief pressure build-up survey after which AWE will run a series of flow tests at various choke settings, rates, and wellhead pressures. The Waitsia-3 evaluation will be followed by similar tests on the Waitsia-2 and Waitsia-4 wells.

The test program is designed to determine well deliverability from the southern extent of the field and to collect gas samples for compositional analysis.

The zone being tested in Waitsia-3 is the Kingia sandstone where a 42-m interval has been perforated between 3,248 m and 3,290 m measured depth.

The test program for all three wells is expected to be completed by the end of November.

Waitsia field lies in production licences L1/L2 about 20 km east-southeast of Dongara.

AWE is operator with 50% and Lattice Energy-recently acquired by Beach Energy Ltd.-holds the remaining interest.

BHP offers details about LeClerc discovery

BHP Billiton Ltd.'s LeClerc discovery, drilled in the deep water offshore Trinidad and Tobago, has found 4-5 tcf of natural gas, according to the Caribbean twin-island nation's Minister of Energy and Energy Industries Franklyn Khan.

"Trinidad and Tobago is a mature province on the continental shelf and therefore we do not expect huge finds…but in the deep water where we have not yet explored, we are expecting large finds," Khan said.

Earlier this year BHP reported making its LeClerc discovery but never revealed the find's size.

Geraldine Slattery, BHP's asset president, conventional, told the Trinidad and Tobago Energy Conference that the discovery was the first in the Caribbean's deep water. "We are very encouraged by the large potential gas resource found in the LeClerc on Block 5 with gas penetrating multiple horizons," she said.

"We are currently evaluating recoverable gas volume as well as conditions both above and below ground necessary to support the further appraisal of that potential," Slattery said. "We were also very pleased to have oil shows in the deep of that well-a strong indication of a liquid hydrocarbon system which supports prospectivity for oil in the southern play."

Royal Dutch Shell PLC is BHP's partner in LeClerc, and the company told the media that it wants to produce deepwater gas from the discovery by 2026. Derek Hudson, the company's country manager, said the plan was to bring on LeClerc to drive the future gas development in Trinidad and Tobago.

Hudson said BHP and Shell will be returning to LeClerc to drill extension wells to further appraise the size of the discovery but is clear it can be produced within the next decade.

BHP Billiton is expected in 2018 to drill two more exploration wells in the deep water offshore Trinidad and Tobago.

Pilot, Black Swan to sell Exmouth Plateau interest

Pilot Energy Ltd., Sydney, and its joint-venture partner Black Swan Resources Pty. Ltd., Perth, have put an unencumbered 100% of their Exmouth Plateau permit WA-507-P up for sale.

The prospective permit has an aerial extent of 1,622 sq km and lies north of Thebe, Jupiter, and Scarborough gas fields-all of which have gas resources in the multitrillion cubic feet range, although yet to be developed.

WA-507-P is covered by a 3D seismic dataset that was acquired in 2010. The combine has interpreted the data to map three large prospects at the Mungaroo reservoir level named Dalia Updip, Beta, and Gamma.

The prospects were evaluated in 2015 by consultants Gaffney Cline & Associates, which confirmed a combined best case prospective resource of 1.6 billion bbl of oil or 10 tcf of gas.

Pilot, with 80% interest in the block, said the sale will enable the company to focus on its Perth basin interests.

Black Swan, currently holding the remaining 20%, has agreed to manage the sale process and data room in Perth on behalf of the combine.

Drilling & ProductionQuick Takes

ESAI: Dwindling megaprojects slow oil sands growth

ESAI Energy LLC forecasts leaner and smaller Canadian oil sands projects in the coming years as producers face high costs in a recovering oil-price environment.

The Boston consultancy forecasts oil sands production growth will decelerate to 120,000 b/d in 2019 from 250,000 b/d in 2018, noting that producers are being selective in their allocation of capital to growth projects.

Suncor Energy Inc.'s operated 190,000-b/d Fort Hills mine, due for startup by yearend, might be the last greenfield mining project in the oil sands for several years, ESAI Energy says. That project was sanctioned in 2013.

While operators are experimenting with solvents and new processes that have the potential to reduce both costs and emissions, new greenfield projects are unlikely to go forward until after 2020. ESAI Energy expects incremental growth will continue from expansions to existing steam-assisted gravity drainage projects that require less initial capital outlays and that can come online in less time.

Pipeline capacity to accommodate production growth also is proving to be elusive as lengthy regulatory reviews and court challenges delay projects. Current takeaway capacity for surplus Canadian crude remains constrained until Enbridge Inc.'s Alberta Clipper Line 67 expansion comes online in late 2018 and provides some temporary relief.

"Even with decelerating growth in 2019, additional capacity beyond the Line 67 expansion will be needed to accommodate production growth after 2019," said Elisabeth Murphy, ESAI Energy analyst.

ExxonMobil launches Vaca Muerta pilot project

ExxonMobil Corp. is to launch a Vaca Muerta pilot project that could lead to a staged development of about 300 horizontal wells with an estimated production of 11 million cu m/day once completed. Argentina's Neuquen province has approved the company's 35-year development for Los Toldos I South Block 85 km northwest of Anelo and 175 km northwest of Neuquen City. Initial project investment is $200 million, said ExxonMobil Exploration Argentina SRL (EMEA), which will operate the block with 80% interest. Gas y Petroleo del Neuquen SA and Tecpetrol each hold 10%.

The initial investment calls for a pilot project that brings as many as seven wells to production, the construction of production facilities, and development of export infrastructure.

ExxonMobil holds six unconventional and one conventional block in Argentina's Vaca Muerta shale. The company has invested $500 million in the region since entering the area in 2011.

Aramco, Rowan begin ARO Drilling operations

ARO Drilling, a 50-50 joint venture of Saudi Aramco and Rowan Cos. PLC, started operations on Oct. 17, Rowan reported.

As part of the startup, Aramco and Rowan contributed equal cash to the combine, which subsequently acquired one jack up rig from Aramco and three jack ups from Rowan, including the previously idle JP Bussell.Following the rig purchases, ARO Drilling distributed excess cash totaling $88 million to each of Aramco and Rowan, maintaining each party's 50% ownership interests in the group.

Pursuant to the ARO Drilling shareholders' agreement, the combine will buy another jack up from Aramco in 2017 and two more from Rowan once they complete their current contracts in late 2018. ARO Drilling also now manages Rowan's seven remaining jack ups currently in Saudi Arabia.

The JV also plans to purchase 20 future newbuild rigs that will be constructed by an Aramco manufacturing JV and are expected to be delivered between 2021 and 2030. Each newbuild is expected to have a 16-year drilling commitment upon delivery to ARO Drilling.

"This is a groundbreaking joint venture that supports Saudi Arabia's Vision 2030 and provides Rowan with an unparalleled long-term growth opportunity throughout the next decade and beyond," commented Thomas P. Burke, Rowan president and chief executive officer.

Aramco last year signed agreements with both Rowan and Nabors Industries Ltd. to launch separate drilling combines. Aramco in May signed deals totaling a reported $50 billion with various US firms that will pave the way for the state-run firm to "enhance its business synergy with the US as well as attract investments from its US counterparts to the kingdom."

Contract let for West White Rose drilling package

In preparation of the 2022 startup of Husky Energy Inc.'s West White Rose project, Wood Group Canada Inc. has let a contract to MHWirth AS, a unit of Akastor ASA, for the delivery of a drilling package, including equipment, engineering, and services.

West White Rose lies 350 km southeast of Newfoundland and Labrador in White Rose field. White Rose field is more than 200 miles east of St. John's on the eastern edge of the Jeanne d'Arc basin in 393 ft of water.

The drilling package will be designed as a fixed facility with a platform supported by a concrete gravity structure. Primary functions of the platform will include drilling and limited processing facilities with permanent accommodations.

MHWirth's contract covers the majority of equipment and an engineering scope.


Leak forces brief evacuation of Mongstad refinery

Statoil ASA was investigating the cause of a naphtha leak that led to an evacuation and partial shuttering of Statoil Refining Norway AS' 9.3 million-tonne/year in Mongstad, Norway.

Reported to Statoil's emergency center on Oct. 24 at 7:14 a.m. local time, the leak forced shutdowns of unidentified parts of the refinery as well as an evacuation of 108 plant employees not part of the operator's emergency response team (ERT), which was mobilized to handle the situation, Statoil said.

While Statoil confirmed the ERT stopped the leak by 9:02 a.m. with no injuries reported resulting from the event, the company disclosed no further details regarding the status of current operations at the refinery or where inside the plant the leak was detected.

Statoil said it would investigate the cause of the incident.

Last year, a 35-cu m oil spill occurred at the Mongstad refinery due to corrosion in a pipe at the site, the company said in its 2016 annual report to investors.

Philippines' sole naphtha cracker gets expansion

JG Summit Petrochemicals Group (JGSPG), a wholly owned subsidiary of JG Summit Holdings Inc., has let a contract to Fluor Corp. to provide engineering, procurement, and construction management (EPCM) for the utilities, off sites, and infrastructure for an expansion of JGSPG's petrochemical complex in Barangay Simlong, Batangas City, Philippines, 120 km south of Metro Manila overlooking Batangas Bay.

Alongside EPCM for utilities, off sites and infrastructure, Fluor also is providing program management services for the expansion project, which will increase JGSPG's ethylene production by 160,000 tonnes/year and propylene production by 50,000 tpy, Fluor said.

The expansion is scheduled to be completed by yearend 2020, the service company said.

Fluor, which booked the order in third-quarter 2017, did not disclose a value of the EPCM contract.

Operated by JG Summit Olefins Corp. (JGSOC), JGSPG's petrochemical complex houses the Philippines' first and only naphtha cracker, which-commissioned in 2009 at a cost of $700 million-uses process technology from Lummus Technology to produce 320,000 tpy polymer-grade ethylene and 190,000 tpy of polymer-grade propylene.

JGSOC's production is used as feedstock for fellow JGSPG unit JG Summit Petrochemical Corp.'s polymers plant at the complex, which produces 320,000 tpy of polyethylene and 190,000 tpy of polypropylene, JGSPG's web site states.


ExxonMobil buys Delaware basin crude terminal

ExxonMobil Corp. has acquired a crude oil terminal in Wink, Tex., part of the Delaware basin, from Genesis Energy LP. It will be ExxonMobil's first Permian terminal to be anchored by its recently acquired Delaware basin acreage.

The terminal handles Permian crude and condensate for transport to Gulf Coast refineries and marine export terminals. The facility is interconnected to Plains All American Pipeline LP's Alpha Crude Connector pipeline system and is permitted for 100,000 b/d of throughput with the ability to expand.

"The terminal provides crude producers with a full range of logistical options including truck, rail, and inbound and outbound pipeline access not only for ExxonMobil's production but for all Permian basin producers," commented Gerald Frey, president of ExxonMobil Pipeline Co. "It also provides shippers with efficient and cost-effective access to market destinations in the Gulf region."

West Texas LPG system to expand system

West Texas LPG Pipeline LP, a joint venture of operator Oneok Inc. and Martin Midstream Partners LP, plans to invest $200 million to expand its natural gas liquids system into the Delaware basin.

The extension includes the construction of a 120-mile, 16-in. pipeline lateral with an initial capacity of 110,000 b/d, as well as the construction of two pump stations and pipeline looping along the existing West Texas LPG system that will increase its capacity to handle the dedicated volume.

The project, which is expected to be completed in third-quarter 2018, is supported by long-term dedicated NGL production from two planned third-party natural gas processing plants in northern Reeves County, Tex., which the partnership estimates will produce up to 40,000 b/d.

West Texas LPG Pipeline consists of 2,600 miles of NGL pipeline in Texas and New Mexico and provides transportation to the Mont Belvieu market center from nearly 40 third-party gas processing plants in the Permian basin. West Texas LPG Pipeline is owned 80% by Oneok and 20% by Martin Midstream.

US DOS okays Alberta Clipper capacity increase

Enbridge Energy LP received a presidential permit from the US State Department authorizing it to increase transport up to full design capacity of roughly 890,000 b/d across a 3-mile segment of its Line 67 Alberta Clipper crude oil pipeline at the US-Canada border near Neche, ND, for continued shipment to an existing Enbridge terminal in Superior, Wis.

The pipeline, originally permitted in 2009 and built in 2010, has been operating at 450,000 b/d. Enbridge first applied for the expanded capacity in 2012. Line 67 starts in Edmonton, Alta.

Enbridge had been transferring crude at Neche to its already permitted Line 3 system as a workaround while awaiting permitting of the additional Alberta Clipper capacity.

The company plans to replace most of Line 3 with new pipe but has met growing popular opposition in the US. Minnesota began public hearings on the project last month.