OGJ Newsletter

GENERAL INTEREST Quick Takes

BOEM plans Gulf of Mexico lease sale 

The US Bureau of Ocean Energy Management plans to hold a Gulf of Mexico-wide oil and gas lease sale in November that will include all available unleased areas in federal waters—some 14,755 blocks—covering about 78.8 million acres.

Lease Sale 256 was originally scheduled for August, but “due to the need to conduct additional analysis to consider recent changes in the oil and gas markets, which were due in part to the COVID-19 pandemic,” BOEM said, the sale was rescheduled.

Fiscal terms include a 12.5% royalty rate for leases in less than 200 m (656 ft) of water, and a royalty rate of 18.75% for all other leases issued pursuant to the sale, in recognition of current hydrocarbon price conditions and the marginal nature of remaining Gulf of Mexico shallow-water resources.

Excluded from the lease sale are blocks subject to the congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006; blocks adjacent to or beyond the US Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap; and whole blocks and partial blocks within the current boundaries of the Flower Garden Banks National Marine Sanctuary.

This will be the seventh offshore sale in the Department of Energy’s Outer Continental Shelf 2017-22 program.

BOEM estimates the upcoming sale contains 48 billion bbl of undiscovered technically recoverable oil and 141 tcf of undiscovered technically recoverable gas.

All terms and conditions for Lease Sale 256 are available on the BOEM website. Due to the COVID-19 pandemic, bids are only being accepted by mail.

Strata-X Energy, Real Energy to merge 

Strata-X Energy Ltd., Brisbane, and Real Energy Corp. Ltd., Sydney, signed an agreement to merge interests into a new gas operator called Pure Energy Corp. Ltd.

The move will bring together the companies’ holdings in Cooper and Surat basins of Queensland, including the 50-50 joint venture of the Venus project in Surat.

Pure Energy plans to use innovative well completion and non-fracturing reservoir enhancement methods to prove up commercial gas flows during the next 12 months, the companies said.

The key development is the Venus coal seam gas project in permit ATP 2051 on the Walloon CSG fairway south of Senex’s Atlas project and Central Petroleum’s Range project.

Work on the proposed Connor-1 well re-entry is expected to begin in August. The program is designed to prove sufficient water flows to enable dewatering and early gas flows from the Walloon coals.

If the re-entry flow test goes to plan, the JV expects to drill two wells offsetting Connor-1 and fully equip all three wells as a production pilot program.

The coals are immediately adjacent to gas infrastructure and are prospective for CSG over the entire 152-sq km permit.

A recent independent review of the data in and around the permit certified a prospective gas resource of 694 petajoules.

Gulf Energy farms in to North West Gemsa license  

Gulf Energy, a private Egyptian oil and gas company, has acquired SDX Energy PLC’s 50% working interest in the late-life, NPIC-operated North West Gemsa license in Egypt’s Eastern Desert.

North West Gemsa is an 83-sq km onshore concession some 300 km southeast of Cairo adjacent to the Gulf of Suez. It consists of three main oilfields: Al Amir SE, Al Ola, and Geyad, which produce light 42-degree API oil.

In 2018, a three-well infill drilling program was undertaken together with a seven-well workover program. The gross production target for full-year 2019 was 3,000-3,200 boe/d.

Gulf Energy paid $3 million for the interest, of which $1.4 million has been used to discharge the SDX’s remaining liabilities on the license.

Elsewhere in Egypt, SDX has a working interest in three producing assets: a 55% operated interest in South Disouq gas field in the Nile Delta, a 50% non-operated interest in the West Gharib concession onshore in the Eastern Desert, and a 12.75% non-operated interest in the South Ramadan concession offshore Gulf of Suez.

WA releases four exploration areas for competitive bidding 

The Western Australian government has released four exploration areas onshore and in state waters for competitive bidding. Two areas are in the Carnarvon basin and two in the North Perth basin.

Area L20-1 covers onshore and offshore state waters in the northern Carnarvon basin around Onslow and contains more than 50 previous wells, mostly drilled onshore.

Four wells have been drilled offshore, including the Cowle-1 wildcat that flowed oil at rates up to 1,600 b/d from reservoir sands in the Flacourt formation.

The area also contains extensive 2D seismic data available to applicants.

Area L20-2 is onshore in the southern Carnarvon basin, inland from Exmouth. It is said to be a shale play with good potential gas-prone source rocks.

It has been covered by numerous seismic surveys, but contains only three previous wells. One, drilled by ExxonMobil in 1985, targeted the Moogooloo sandstone but was abandoned for lack of seal.

Area L20-3, onshore North Perth basin surrounding the town of Eneabba, contains only one previous well—a dry hole drilled in 2013 targeting the Cadda formation and the Cattamarra coals.

Area L20-4 is onshore in the North Perth basin near Moora and Dongara oil field. It contains three previous wells—Cypress Hill-1 (1988) and Yallalie-1 (1991) northwest of Moora, and Dandaragan-1 that targeted an extension of Dongara field.

The permit is prospective for both oil and gas.

Prospective applicants must provide detailed work program commitments and have until Oct. 19 to lodge bids.

Exploration & Development Quick Takes 

ReconAfrica subsurface evaluation to aid Kavango basin exploration program 

Reconnaissance Energy Africa Ltd. (ReconAfrica) completed a subsurface evaluation delineating large scale, prospective conventional hydrocarbon bearing structures throughout the Kavango basin.

The study will aid a 3-well exploration program scheduled for fourth-quarter 2020 to test organic rich shales and more shallow conventional structures to confirm a thick, active, petroleum system throughout the sedimentary basin, the company said in a press statement July 7 (OGJ Online, Feb 17, 2020).

A new, extended high-density Aero-Mag survey and other new ancillary data coupled with Halliburton’s LithoTect structural interpretation tool have generated a thorough understanding of how deep Permian rift basin developed, the company said. Specifically, a faulting system has been identified throughout the basin which is responsible for potential conventional fault and stratigraphic hydrocarbon bearing structures. This work builds on the unconventional potential previously identified.

The deep Kavango basin extends from northeast Namibia to northwest Botswana. Namibian petroleum license PEL 73 covers an area of 25,341.33 sq km (6.3 million acres) and Botswana petroleum license PEL 001/2020 comprises 9,921 sq km (2.45 million acres), contiguous to the Namibian license.

ReconAfrica holds 90% interest in PE 73 and the Namibian state oil company (NAMCOR) holds the remaining 10%. ReconAfrica holds 100% interest in PEL 001/2020.

Joint venture formed to explore and develop Russia’s Orenburg Oblast 

Gazprom Neft, Lukoil, and Tatneft have established a joint venture, New Oil Production Technologies LLC, for exploration and production of hydrocarbon reserves in Russia’s Orenburg Oblast, including the Savitsky and Zhuravlevsky license blocks. Pilot development is expected to start in 2024.

Savitsky covers an area of 900 sq m across Buzulksky and Grachevsky districts of the Orenburg Oblast and is marked by a high level of geological uncertainty. Drilling of the first prospecting and appraisal well is concluding. The full geological prospecting program includes six horizontal wells. The partners will undertake a range of geophysical investigations, including core and fluid sampling and analysis, research and development, and non-seismic field investigations. An area of 880 sq km has undergone 3D seismic surveying.

Zhuravlevsky covers an area of about 120 sq km in Buzulksky district and abuts Savitsky. It contains Zhuravlevskoye field, discovered in 1965 but currently mothballed. Reserves in place are about 2.5 million tonnes of oil. Hard-to-recover reserves may also be present.

Geological prospecting at Zhuralevsky, expected to run from 2020 to 2023, includes 118 sq km of 3D seismic and drilling of a prospecting well in traditional reserves. An additional horizontal prospecting and appraisal well will be drilled in non-traditional reserves. A pilot development program will commence once exploration activities are complete and reserves confirmed.

Each party has been allocated an equal one-third interest in the joint venture.

ENI to explore development options for gas discovery offshore Egypt 

Eni SPA and partners will screen development options for a gas discovery made through drilling the first exploration well in the North El Hammad license in the conventional Egyptian waters of the Nile Delta. The companies aim to fast track production through existing infrastructure.

The Bashrush discovery lies in 22 m of water, 11 km from the coast, 12 km northwest of Nooros field, and about 1 km west of Baltim South West field. Both fields are in production (OGJ Online, Jan. 9, 2017). The well encountered a single 152-m thick gas column within Messinian age sandstones of the Abu Madi formation with excellent petrophysical properties. It will be tested for production.

The discovery demonstrates significant Messinian gas and condensate potential in this sector of Egyptian offshore shallow waters and further extends gas potential west of Abu Madi formation reservoirs, discovered and produced from the Great Nooros area, Eni said.

Eni will continue to explore Great Nooros by drilling exploration well Nidoco NW-1 DIR on the Abu Madi West concession later this year.

Eni, in participation with Egyptian Natural Gas Holding Co. (EGAS), is operator in North El Hammad with 37.5% interest through affiliate IEOC. Partners are BP (37.5%) and Total (25%).

Drilling & Production Quick Takes 

BP gains environmental green light for Ironbark-1 

BP plans to spud Ironbark-1 off Western Australia in this year’s third quarter following approval of its environmental plan by the Australian National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) (OGJ Online, Dec. 13, 2019).

The well, in permit WA-359-P, will be drilled 170 km off Karratha in about 300 m of water using the Ocean Apex drilling rig. The prospect is 50 km from the North Rankin gas platform and also close to Pluto and Wheatstone fields. The well is expected to take about 100 days to drill, evaluate, plug, and abandon.

Ironbark could hold up to 15 tcf of gas across multiple targets within the Triassic Mungaroo formation, a reservoir that hosts commercial discoveries on the North West Shelf, including Gorgon, Goodwyn, North Rankin, and Perseus fields.

Ironbark-1 will be drilled to a total depth of 5,500 m which will be the deepest offshore well ever drilled in Australia.

BP is operator of the joint venture with 41.5%. Beach Energy has 21%, Cue Energy 21.5%, and New Zealand Oil and Gas 15%.

CNOOC begins Luda 21-2/16-3 regional development 

CNOOC Ltd. started production at the Luda 21-2/16-3 regional development project. The project is in Liaodong Bay of Bohai Sea, about 39 km north of Luda 10-1 oilfield and 90 km northwest of Suizhong 36-1 onshore terminal, in about 25 m of water.

The project has built one central platform, three wellhead platforms, and one adjacent production platform. A total of 69 development wells are planned. Peak production of 25,600 bo/d is expected in 2022.

CNOOC holds 100% interest in the project.

Norway production decreased in June, NPD says 

Norway’s daily production averaged 1.857 million b/d in June, the Norwegian Petroleum Directorate reported. Norway’s daily production averaged 2.029 million b/d in May (OGJ Online, June 19, 2020)

On Apr. 29, the government decided to implement a cut in Norwegian oil production. The production figures for oil in June include this cut of 250,000 b/d. Oil production in June is 4.1% under the limit set in connection with the production adjustment for June.

The average daily liquids production included 1.543 b/o, 298,000 bbl of NGL, and 17,000 bbl of condensate.

The update takes the authorities’ oil production regulation into account, as well as delayed startup of fields under development and oil production in the first quarter.

Total petroleum production for the first 6 months in 2020 is about 115.2 million standard cu m oil equivalents.

Vår Energi to resume Barents, North Sea drilling 

Vår Energi will resume drilling in late autumn 2020 in the Barents Sea and the North Sea after postponement earlier this year due to the COVID-19 pandemic and oil price collapse.

The campaign includes two producers and one water injector at Goliat field in PL 229 in the Barents Sea, and the King Prince exploration well near Balder-Ringhorne field in the North Sea. Saipem-owned Scarabeo 8 will do the drilling.

Activity has resumed from temporary changes in the petroleum tax, adopted by the Norwegian parliament in June, triggering a positive employment effect in the rig market.

Vår Energi is jointly owned by Eni (69.6 %) and HitecVision (30.4 %).

PROCESSING Quick Takes 

Hess Midstream delays Tioga gas plant turnaround 

Hess Midstream LP has deferred until 2021 a planned maintenance turnaround at its 250-MMcfd Tioga gas plant (TGP) in North Dakota, originally scheduled for third-quarter 2020, “to ensure safe and timely execution given the COVID-19 pandemic.”

The company said completion of its 150-MMcfd TGP expansion is expected by end-2020. The expansion will add residue and y-grade liquids processing capacity to the existing full-fractionation and ethane-extraction capability of the current plant (OGJ Online, Apr. 26, 2019).

Incremental gas processing capacity is expected to be available in 2021 upon completion of the turnaround, during which both the expansion and residue and NGL takeaway pipelines will be tied in.

There is no change to Hess Midstream’s previously announced full-year 2020 financial guidance and expected 25% growth in 2021 earnings compared with full-year 2020. 

Sasol sheds interest in Escravos GTL plant 

Sasol Ltd. has signed an agreement to sell its indirect beneficial interest in the Escravos gas-to-liquids (EGTL) plant in Escravos, Nigeria, to Chevron Corp.

The July 1 transaction—which has an agreed economic effective date of Sept. 1, 2019—releases Sasol from associated company guarantees and other obligations related to the EGTL plant, Sasol said.

Sasol, however, will continue to support Chevron in performance of the EGTL plant via ongoing catalyst supply, technology, and technical support.

The interest divestment comes as part of Sasol’s comprehensive response strategy to mitigate the impact of lower oil prices caused by the coronavirus (COVID-19) pandemic, the operator said.

Sasol held a 10% interest in the Chevron-operated EGTL plant, which has the capacity to process 325 MMcfd into 33,000 b/d of liquids—principally synthetic low-sulfur diesel—for cars and trucks. Nigerian National Petroleum Corp. also is a partner in the EGTL plant, which entered operation in 2014, according to Chevron’s website.

Uruguay’s ANCAP lets contract for La Teja refinery 

Uruguay’s state oil company Administración Nacional de Combustibles Alcohol y Pórtland (ANCAP) has let a contract to KBR Inc. to provide technology for a new unit to be added as part of a strategic upgrading project at ANCAP’s 50,000-b/d Eduardo Acevedo Vázquez refining complex at La Teja, along the Bay of Montevideo.

As part of the contract, KBR will license its residual oil solvent extraction (ROSE) solvent deasphalting (SDA), as well as deliver basic engineering design, and proprietary equipment for the 6,000-b/d ROSE unit, the service provider said.

In addition to helping reduce the site’s environmental footprint, the ROSE unit will enable the refinery—Uruguay’s only—to produce a lighter, higher-grade product mix, as well as allow it greater flexibility in adjusting production slates to respond to changing market conditions, KBR said.

While further details regarding the La Teja upgrading project were not disclosed, ANCAP confirmed in its 2019 annual report to investors that it will carry out modifications and equipment upgrades designed to improve economics, efficiency, and environmental performance to main processing units at the refinery during the complex’s next planned maintenance shutdown, which is scheduled for 2023.

Already in the planning stages, the 2023 turnaround also will implement a project involving coprocessing cheaper, low-cost renewable feedstocks into fuel, ANCAP said.

TRANSPORTATION Quick Takes 

AGL submits environmental plans for proposed LNG terminal 

AGL Energy, Sydney, has submitted for public comment an environmental effects statement for its proposed LNG import terminal at Crib Point on Westernport Bay, south of Melbourne in Victoria (OGJ Online, Oct. 12, 2018).

The $300 million (Aus.) plan involves a floating terminal moored at a newly constructed jetty, with input supply LNG carriers mooring alongside. Construction includes a 55-km gas pipeline to Pakenham to connect to the Victorian grid.

AGL says construction could begin in 2021 and the project brought on stream by 2023, in time to help meet the shortfall of gas supply predicted for Australia’s southeast market.

The project faces opposition from environmental groups as well as residents concerned about potential risks to the Westernport region’s ecosystems and tourism.

The project also faces opposition from Federal Government minister Greg Hunt, whose electorate encompasses the region. Hunt believes an LNG terminal planned for Port Kembla in New South Wales by a group headed by Western Australian entrepreneur Andrew Forrest is superior and less environmentally sensitive (OGJ Online, Apr. 29, 2019).

The Crib Point proposal requires approval from both the Victorian and the federal governments.

The AGL plan is one of two similar projects proposed in Victoria following Viva Energy’s announcement in June of its ambitions to transform the site of its Geelong oil refinery into an energy hub that includes an LNG import capability.

The AGL environmental effects statement will be open for public comment until Aug. 26. Subject to clearance, AGL hopes to make a final investment decision on the Crib Point project around the end of this year.

Williams Leidy South Transco expansion gets FERC approval 

Williams Cos. Inc. received approval from the US Federal Energy Regulatory Commission (FERC) for its 582-MMcfd Leidy South expansion project. The project will connect natural gas produced by Cabot Oil & Gas Corp. and Seneca Resources Co. LLC in the Marcellus and Utica regions of Pennsylvania with markets along the Atlantic seaboard by the 2021-22 winter heating season, Williams said. UGI Utilities Inc. will use its capacity to directly serve retail customers in northeast Pennsylvania.

Leidy South will include construction of two greenfield compressor stations, a 46,930 hp unit in Luzerne County, Pa., and 31,871 hp in Schuylkill County, Pa. (OGJ Online, Nov. 4, 2019). The project will use Williams’ existing Transco transmission corridor, replacing 6.3 miles of existing 24-in. OD Leidy Line A pipe with 36-in. OD pipe in Clinton County, Pa., and building 5.9 miles of new loop segments. It will also add horsepower at two existing compressor stations (12,000 hp in Wyoming County, Pa., and 35,871 hp in Columbia County, Pa.)

Seneca, Cabot, and UGI have binding, 15-year commitments for 100% of the project’s capacity.

Williams filed for FERC approval in August 2019.

Rangeland places Alberta crude, condensate gathering system in service 

Rangeland Midstream Canada Ltd. has placed its 85-km Marten Hills pipeline system in service. The system consists of new crude oil and condensate pipelines in the Marten Hills region of north central Alberta, terminating at an interconnect with Plains Midstream Canada’s Rainbow pipeline system, which serves the Edmonton, Alta., hub and refining market.

Marten Hills is anchored by long-term transportation agreements with three of the region’s largest crude oil producers, which have made a combined minimum volume commitment representing 40% of the system’s capacity, Rangeland said. The agreements span a 450,000-acre area of mutual interest dedicated to the Marten Hills system. 

Rangeland started building Marten Hills in October 2019 and put it into service just 1 week later than planned (OGJ Online, Oct. 16, 2019).