OGJ Newsletter

Exploration & DevelopmentQuick Takes

Bashneft finds oil in southwestern Iraq

Bashneft International has discovered an oil field named Salman on Block 12 in southwestern Iraq, parent Rosneft reported. The discovery, which Rosneft called the first exploratory well on the block, went to 4,277 m. No other details were reported.

Block 12 covers 7,680 sq km in an unexplored area of the Arabian Plate about 80 km south of As-Samawah and 130 km west of Nasiriyah.

Equinor unit, SOCAR plan joint Caspian work

A 50-50 joint operating company formed by Statoil Azerbaijan and State Oil Co. of Azerbaijan Republic (SOCAR) will appraise and develop Karabagh oil field in the Caspian Sea and explore an area to the northwest under agreements signed May 30.

The Karabagh work will include the drilling of an appraisal well this year under a risk-service agreement that envisions installation of a platform and first production in 2021.

Karabagh is in 150-200 m of water 120 km east of Baku, just north of Azeri-Chirag-Deepwater Gunashli (ACG) oil field operated by Azerbaijan International Operating Co. The structure was identified by seismic data in 1959 and confirmed by drilling in 1997-98. SOCAR and Statoil Azerbaijan both have partnership interests in AIOC.

The exploration, starting with a seismic survey, will occur under a production-sharing agreement in an area designated Ashrafi-Dan Ulduzu-Aypara northwest of Karabagh field.

Prospects at Dan Ulduzu and Ashrafi are in 80-180 m of water 100-110 km northeast of Baku. Aypara, identified by seismic surveys in 1980, is in open sea 90 km northeast of Baku.

Statoil Azerbaijan soon will be renamed Equinor Azerbaijan to align with the new name of its parent company.

Forest 3D survey tests line-free method

A Calgary geophysical services firm has acquired ultrahigh-density 3D seismic data over a small area without seismic lines or trails using technology designed to reduce forest disturbance.

Explor Geophysical Ltd. said data density was 100 million traces/sq km at full offset with trace densities exceeding 42 million traces/sq km at target depth in its first noncommercial-scale application of the proprietary technology.

It shot the test survey through a riparian area where other methods are prohibited by regulators concerned about caribou.

Explor said typical low-impact seismic surveys in the forested oil sands region of Alberta require mulch lines 1-7.5-2.75 m wide, 30-80 m apart to accommodate equipment. Conventional surveys had line widths of 6-8 m.

Wolves still use the narrowest mulched lines to prey on boreal woodland caribou, Explor said, citing recent research.

The company conducted the test survey, without cutting any trees, outside the traditional winter operating season for seismic surveys in the boreal forest.

It said commercialization of the technology would enable operators of steam-assisted, gravity drainage projects to acquire seismic data throughout the year and in now-prohibited areas that create coverage gaps.

Typical uses of seismic data for SAGD operations include caprock imaging and reservoir characterization.

Egdon to reapply for Wressle development

Egdon Resources PLC said it soon will submit a new planning application to develop its Wressle oil discovery in the UK after acquiring 5% interests each in onshore Petroleum Exploration and Development Licenses 180 and 182 from Celtique Energie Petroleum Ltd.

Celtique also is selling 12.5% interests in the licenses each to partners Union Jack Oil PLC and Humber Oil & Gas Ltd.

Wressle development would not involve hydraulic fracturing, which has encountered political resistance in England, the only UK country where it is allowed. But its original application was rejected by local authorities (OGJ Online, July 3, 2017).

Egdon said its new planning application will have additional information from site-investigation boreholes and two deeper cored boreholes that addresses concerns raised by officials.

Interests after the Celtique transactions will be Egdon and Europa Oil & Gas PLC, 30% each; Union Jack Oil, 27.5%; and Humber Oil & Gas, 12.5%.

Cluff gets southern UK North Sea waivers

Cluff Natural Resources PLC, London, has 6 extra months during which to find financing for drilling on two promote licenses it acquired in the southern North Sea during the UK’s 28th licensing round in 2014.

The Oil & Gas Authority has waived its requirement for conclusion of a farmout by May 31 on Licenses P2248 and P2252.

The company said it will “continue the farmout process” while “also exploring various additional forms of financing which will support its ultimate aim of drilling one or more wells on these licenses.”

The promote period and initial term of each license will continue to Nov. 20, subject to a drill-or-drop decision by Sept. 30.

On P2248, Cluff has identified a Carboniferous prospect designated Cadence on Quadrant 43/11.

Prospects on P2252 are Pensacola, an Upper Permian Zechstein reef structure, and Lytham-Fairhaven, a Hauptdolomite platform carbonate in the Zechstein formation in which past drilling has encountered natural gas. P2252 quadrants are 41/5, 41/10, and 42/1.

Cluff holds 100% interests in the licenses.

Drilling & ProductionQuick Takes

Shell begins production from Kaikias in gulf

Shell Offshore Inc. started production from Phase 1 of the Kaikias deepwater project in the US Gulf of Mexico, a year ahead of schedule. Kaikias, in the Mars-Ursa basin 130 miles offshore Louisiana, is owned by Shell (80% working interest), as operator, and MOEX North America LLC (20% working interest), a wholly owned subsidiary of Mitsui Oil Exploration Co. Ltd. Estimated peak production is 40,000 boe/d.

Shell took financial investment decision in February 2017 and has reduced costs by about 30%, lowering the forward-looking, break-even price to less than $30/bbl.

Shell discovered Kaikias in August 2014. The development, in 4,500 ft of water, sends production from its four wells to the Shell-operated (45%) Ursa hub, which is co-owned by BP PLC (23%), ExxonMobil Corp. (16%), and ConocoPhillips (16%). From the Ursa hub, volumes flow into the Mars oil pipeline.

Shell lets hull, topsides contract for Vito FPU

Shell Offshore Inc. has let a contract to Sembcorp Marine Rigs & Floaters Pte. Ltd., a wholly owned subsidiary of Sembcorp Marine Ltd., to construct and integrate the hull, topsides, and living quarters of the Vito semisubmersible floating production unit (FPU) in the Gulf of Mexico.

Vito, which lies in more than 4,000 ft of water about 150 miles southeast of New Orleans, is expected to reach peak production of 100,000 boe/d. The development has a recoverable resource of 300 million boe (OGJ Online, Apr. 24, 2018).

Vito FPU’s four-column semisubmersible hull will support topsides weighing 9,200 tonnes. Shell last year signed a letter of intent with Sembcorp but that hinged on a final investment decision, finalized this year.

Shell said the FID was made with a forward-looking, break-even price estimated to be less than $35/bbl.

Plans call for a simplified host design and subsea infrastructure for Vito, a deepwater development covering four blocks in the Mississippi Canyon area. The development will consist of eight subsea wells with deep (18,000 ft) in-well gas lift and is expected to begin production in 2021.

In 2015, Shell began to redesign the Vito project, reducing cost estimates by more than 70% by simplifying the design and working with vendors in areas including well design and completions, subsea, contracting, and topsides design. Shell owns and operates the Vito development with a 63.11% interest. Statoil USA E&P Inc. holds 36.89%.

Johan Sverdrup topsides set in single lift

Equinor ASA and partners have installed the topsides for the Johan Sverdrup drilling platform offshore Norway in a single left using technology the operator calls “groundbreaking.”

The Allseas Pioneering Spirit heavy-lift vessel installed the 22,000-tonne steel structure in 3 hr after preparations.

Topsides that large until now have been modular because crane vessels can lift no more than 12,000 tonnes at once.

Technology used by the Pioneering Spirit, which has single-lift capacity of 48,000 tonnes, was designed for platform removal.

The drilling platform is the second of four structures to be installed in the first phase of Johan Sverdrup development. The riser platform is in place. The processing and utility-and-accommodation platforms will be installed early next year.

Eight wells drilled in 2016 will be tied back to the drilling platform late this year and early in 2019.

Drilling from the platform will begin after the tie-backs. As many as 48 wells will be drilled in the first and second development phases.

First-phase production is to begin late next year and reach 440,000 b/d. Peak production after the start-up of the second phase in 2022 is expected to be 660,000 b/d.

Contract let for Saudi unconventional gas

Saudi Aramco Pres. and Chief Executive Officer Amin H. Nasser called an “unconventional gas stimulation services contract” signed May 27 with Halliburton “the important next phase of achieving our gas expansion objectives.”

Saudi Arabia’s Unconventional Resources Program, launched in 2013, aims at boosting gas production to meet domestic needs, displace crude oil in power generation, supply feedstock for petrochemicals, and stimulate regional economies.

The lump-sum turnkey Halliburton contract includes hydraulic fracturing and well-intervention services described in an Aramco release as “major.” The contract has a 2-year term with an option for a 1-year extension.

The companies didn’t specify well numbers or production targets. Aramco’s program covers northern Saudi Arabia, South Ghawar, and the Jafurah basin.

DeGolyer & MacNaughton to study Priobskoye EOR

Gazprom-Neft has entered an agreement with DeGolyer & MacNaughton Corp., Dallas, on the selection and use of enhanced oil recovery methods for giant Priobskoye field in the Khanti-Mansi Autonomous District of West Siberia.

The Russian company said DeGolyer & MacNaughton will “analyze the history of the Priobskoye since its discovery, assess the potential for increasing production and increasing the oil recovery factor, formulate recommendations for realizing this potential, and address the immediate challenges and problems in developing the Yuzhny (Southern) license block” of the field. The work will occur during 2018-20.

In an April 2016 announcement about production of the 100 millionth tonne of oil from Yuzhno-Priobskoye, Gazprom-Neft said the field, known to have complex geology, was producing 32,000 tonnes/day from 2,000 wells.

PROCESSINGQuick Takes

Upgrade advances for Jamaica’s sole refinery

Jamaica is progressing with the long-planned and earlier delayed expansion and modernization of the Jamaican-Venezuelan joint venture Petrojam Ltd.’s 36,000-b/d hydroskimming refinery in Kingston, Jamaica (OGJ Online, Apr. 26, 2018).

A technical team comprised of members from the Petroleum Corp. of Jamaica (PCJ) and Petrojam are meeting with previously engaged but as-yet-to-be identified engineering, procurement, and construction contractors for expansion of the state-owned refinery, Andrew Wheatley, Jamaica’s minister of science, energy, and technology, told Jamaica Information Service (JIS).

Providing an update on the status of the expansion to Jamaican legislators on May 29, Wheatley said staff members are working feverishly to advance the first phase of the modernization, which involves installation of a vacuum distillation unit (VDU), according to JIS.

“The money is in place, and the government has made an allocation for this year for us to proceed with the VDU project,” Wheatly said.

The VDU comes as part of the refinery’s plan to produce low-sulfur fuel for the bunkering industry that complies with pending sulfur specifications designed to reduce environmental pollution from the International Maritime Organization (IMO) to take effect in January 2020 (OGJ, Apr. 2, 2018, p. 60).

The project aligns with Jamaica’s intention to be able to supply IMO-compliant fuels to cruise and cargo ships that use the island as a transshipment point.

Wheatly previously confirmed $100 million is now earmarked for Phase 1 of the refinery upgrade by PCJ, which holds 51% interest in the refinery alongside Venezuela’s state-run Petroleos de Venezuela SA (PDVSA) 49%.

In April, Wheatley said Jamaica was in the process of trying to reacquire PDVSA subsidiary PDV Caribe SA’s interest in Petrojam as the parties evaluate potential tax implications related to the reacquisition.

Lukoil’s Perm refinery begins bitumen production

PJSC Lukoil has started production of road bitumen complying with new national standards requiring extended life and advanced durability of materials at subsidiary OOO Lukoil Permnefteorgsintez’s 13.1 million-tpy Perm refinery in Russia’s North Urals region, on the north bank of the Kama River.

An earlier commissioned railway overpass for discharge of fuel oils ensures an efficient utilization rate of the refinery’s petroleum-residue recycling plant and bitumen production capacity, which totals about 2,400 tonnes/day, Lukoil said.

Lukoil Lubricants Co., the company’s wholly owned subsidiary responsible for the marketing of lubricants and asphaltic products, will undertake shipment and marketing of these products, Lukoil said.

The bitumen project follows Lukoil’s 2017 agreement with the Perm region’s transport ministry, under which Lukoil agreed to supply locally produced high-quality bitumen products for road construction.

The Perm refinery, which processes blended crudes from northern Perm Oblast and Western Siberia, most recently completed a $50-million reconstruction of the diesel hydrodearomatization section of the site’s hydrocracking unit to enable hydrodewaxing for expanded production of Euro 5-quality diesel in 2016 (OGJ Online, Oct. 7, 2016).

OMV Petrom wraps turnaround at Petrobrazi refinery

OMV Petrom SA, Bucharest, has resumed operations on May 28 following the on-schedule completion of a major 6-week turnaround at its 4.5 million-tonne/year Petrobrazi refinery in the southeast region of Romania, near Ploiesti City.

The €45-million planned turnaround included periodical maintenance works, inspections, and verifications of refinery installations, OMV Petrom said.

“I am happy that this turnaround, which consisted [of] tens of thousands of different operations, went extremely smooth, without any significant incidents and lost time injuries, while ensuring continuity of supply to our filling stations network,” said Neil Anthony Morgan, OMV Petrom’s executive board member responsible for downstream operations.

With the turnaround completed, the refinery is now fully operational and able to process more than 12,000 tonnes/day of crude, Morgan added.

The Petrobrazi refinery’s next turnaround is scheduled for 2022, OMV Petrom said.

Further details regarding specific projects executed during the turnaround were not revealed.

Between 2005 and 2017, the Petrobrazi refinery benefitted from more than €1.5 billion in investments dedicated to modernization projects, construction of new installations, and environmental projects, enabling the refinery to extend turnaround events to every 4 years beginning in 2014 from its previous annual turnaround schedule (OGJ Online, July 24, 2014).

Construction remains under way at the refinery on a grassroots 200,000-tpy unit that will convert LPG components into Euro 5-quality gasoline and middle distillates beginning in early 2019 (OGJ Online, July 19, 2017).

TRANSPORTATIONQuick Takes

Petronas to join LNG Canada project

Malaysia’s Petronas reported it will take an equity position in LNG Canada, in Kitimat, BC, on Canada’s west coast, through its wholly owned entity North Montney LNG LP (NMLLP).

If approved and on closing of this deal, ownership interests in LNG Canada would be Shell Canada Energy 40%, Petronas (through NMLLP) 25%, PetroChina Kitimat LNG Partnership 15%, Mitsubishi Corp. subsidiary Diamond LNG Canada Ltd. 15%, and Kogas Canada LNG Ltd. 5%.

LNG Canada recently selected the joint venture of JGC Corp. and Fluor Corp. as the engineering, procurement, and construction contractor for the project and is currently finalizing materials in preparation for a final investment decision by joint venture participants.

The transaction announced today does not amount to an FID, which remains pending.

“This marks an interesting turn of events after Petronas cancelled its $36-billion (Can.) Pacific North West project in July 2017,” commented Prasanth Kakaraparthi, senior analyst with Wood Mackenzie. “With nearly 52 tcf of reserves and contingent resources—Canada is the second-largest resource holder in Petronas’ portfolio after Malaysia. Consequently, monetization through LNG is inevitable given the weak outlook for domestic prices,” Kakaraparthi said.

He noted, “Costs will be a major concern for the project. Shell has announced its intent to make a decision by end of this year. But before LNG Canada can take FID, it will need to lower costs and take advantage of the latest tax breaks announced by the BC government.”

Total due stake in Novatek’s Arctic LNG 2

Total SA has signed an agreement with Novatek to acquire a 10% participation interest in the Russian company’s 19.8 million-tonne/year Arctic LNG 2 project on northern Siberia’s Gydan Peninsula.

Novatek plans three liquefaction trains with combined capacities of 19.8 million tpy of LNG from gas produced at Utrenneye gas and condensate field. The trains will be installed atop gravity-based structures in the Gulf of Ob.

The site is across the gulf from Novatek’s Yamal LNG plant, the first 5.5-million-tpy train of which started up late last year.

Total is a 20% partner in Yamal LNG and holds a 19% stake in Novatek. Through its acquired interest and holding in Novatek, Total will have an effective interest of 21.5% in Arctic LNG 2 if Novatek retains its 60% share.

If Novatek decides to reduce its interest in the project, Total will be able to increase its direct share to as much as 15%.

The companies also agreed that Total will have the opportunity to acquire 10-15% direct interests in future Novatek LNG projects on the Yamal and Gydan Peninsulas.

The companies plan to make a final investment decision about Arctic LNG 2 next year, targeting start-up of the first train by the end of 2023.

Utrenneye field has reserves, based on the Russian classification system, of 1.582 billion cu m of natural gas and 65 million tonnes of liquids.