GENERAL INTEREST Quick Takes
Strike signs offtake agreement from West Erregulla
Strike Energy Ltd. has signed an agreement with Wesfarmers subsidiary CSBP to convert its gas supply option to a firm 100 petajoule gas offtake arrangement at a rate of 25 terajoules/day over a period of 11 years.
The gas supply will come from Strike’s proposed Phase 1 development of West Erregulla field in the onshore North Perth basin of Western Australia. The gas supply will provide cash flow to assist in financing and reducing costs of capital of the expected Phase 2 development program, the company said.
The agreement with CSBP will enable Strike to deliver all of its volume from the first day following commissioning completion.
The original option pricing model has been amended to a fixed price with annual escalation. The arrangement simplifies the agreements and supports both the delivery of material free cash flow from West Erregulla’s Phase 1 production and Strike’s return expectations, the company said, adding that it now has a solid platform to secure a high-quality financing solution for the construction program.
The offtake agreement is subject to a final investment decision taken on the project, but it is expected that gas deliveries will begin during first-half 2022.
Petrobras launches binding phase of Santos basin asset sale
Petroleo Brasileiro SA (Petrobras) has started the binding phase of its earlier announced proposal to sell 50-100% of its stake in and transfer operatorship of the BL-S-51 concession in the Santos basin. The asset, 215 km off the coast of Sao Paulo, lies in water depths of 350-1,650 m.
At this stage of the project, process letters are issued to potential buyers qualified in the previous phase with guidelines for due diligence and the submission of binding proposals, Petrobras said Sept. 8.
The BM-S-51 concession was acquired in 2005 and is in the first exploratory period with a remaining minimal commitment to drill one well.
Petrobras is operator with 80% interest. Partner Repsol Sinopec Brasil holds the remaining 20%.
Total signs MoU for Mozambique LNG project security
Total E&P Mozambique Area 1, operator of the Mozambique LNG project, signed a new memorandum of understanding (MoU) with the government of Mozambique regarding the security of Mozambique LNG project activities (OGJ Online, July 17, 2020).
The new MoU provides that a joint task force shall ensure the security of Mozambique LNG project activities in Afungi and across the broader area of operations of the project. Mozambique LNG shall provide logistic support to the joint task force.
Total E&P Mozambique Area 1 Ltda., a wholly owned subsidiary of Total, operates Mozambique LNG with a 26.5% participating interest alongside ENH Rovuma Área Um SA (15%), Mitsui E&P Mozambique Area1 Ltd. (20%), ONGC Videsh Rovuma Ltd. (10%), Beas Rovuma Energy Mozambique Ltd. (10%), BPRL Ventures Mozambique BV (10%), and PTTEP Mozambique Area 1 Ltd. (8.5%).
Mozambique LNG is the country’s first onshore LNG development. The project includes the development of Golfinho and Atum fields within Offshore Area 1 and the construction of a two-train liquefaction plant with a capacity of 13.1 million tonnes/year. The Area 1 contains more than 60 tcf of gas resources, of which 18 tcf will be developed with the first two trains.
The final investment decision was made in June 2019 and the project is expected to come into production by 2024.
Exploration & Development Quick Takes
Eni: Gas discovery offshore Egypt proves, extends Great Nooros potential
Eni and BP will contemplate development options for a new gas discovery in the Great Nooros area in the Abu Madi West development lease in the Mediterranean Sea, offshore Egypt.
Nidoco NW-1 lies in 16 m of water, 5 km from the coast and 4 km north of Nooros field, which was discovered in July 2015. The well encountered gas-bearing sands of 100 m of which 50 m are within the Pliocene sands of the Kafr-El-Sheik formations and 50 m are within the Messinian age sandstone of the Abu Madi formations, both levels with good petrophysical properties.
In the Abu Madi formation, a new level, which was not yet encountered in Nooros field, has been crossed proving the high potential of the Great Nooros area and the further extension of the gas potential to the north of the field, Eni said Sept. 16.
Estimated gas in place in the Great Nooros area is above 4 tcf given preliminary evaluation of well results, considering the extension of the reservoir towards north and the dynamic behavior of the field and recent area discoveries.
Eni, through its subsidiary IEOC, holds a 75% stake in the license of Abu Madi West development lease. BP holds the remaining 25% stake. Petrobel, a 50-50 joint venture of IEOC and the state company Egyptian General Petroleum Corp., is operator.
Apache begins Keskesi exploration offshore Suriname
Apache Corp. commenced operations at the Keskesi East-1 exploration well 14 km southeast of Sapakara West-1 in Block 58 offshore Suriname utilizing the Noble Sam Croft drillship. It will test oil-prone upper Cretaceous targets in the Campanian and Santonian.
The operator also provided an update to the technical evaluation of the offshore Suriname Kwaskwasi-1 discovery well (OGJ Online, July 29, 2020).
As previously noted, Kwaskwasi-1 discovered hydrocarbons in multiple stacked targets in the upper Cretaceous Campanian and Santonian intervals. The well encountered 278 m (912 ft) of net oil and volatile oil-gas condensate pay. The shallower Campanian interval contains 63 m (207 ft) of net oil pay and 86 m (282 ft) of net volatile oil-gas condensate pay. The Santonian interval contains 129 m (423 ft) of net pay. Fluid samples from the Campanian validated the presence of oil with API gravities of 34-43°.
Since July 29, the Noble Sam Croft has gathered reservoir and other technical data in the Santonian. Apache retrieved rotary sidewall cores but was unable to collect representative fluid samples from the reservoir due to conditions caused by cementing operations, which were required to mitigate increased pressure below the base of the Santonian formation. Hydrocarbon shows were observed in the Santonian reservoirs, and the results of the formation evaluation indicate the presence of oil.
Apache holds a 50% working interest in Block 58 and will continue as operator through completion of Keskesi. Total SA holds the remaining 50% working interest.
BW Energy alters Hibiscus-Ruche plans
BW Energy provided an alternative development plan for Hibiscus-Ruche, in the Dussafu Marin permit and associated Ruche Exclusive Exploitation Area (EEA), offshore Gabon. The company will utilize a converted jack up instead of constructing and installing a new wellhead platform (OGJ Online, Nov. 1, 2019). The conversion concept is expected to reduce development capex, time to first oil, and enable a substantial reduction to field development related climate gas emissions by reusing existing infrastructure.
The alternative plan could lower estimated breakeven oil price for phases one and two developments to about $25/bbl Brent, the company said. Production for the two phases combined is expected to peak in 2024 at about 30,000 b/d. A final decision to restart Hibiscus-Ruche is subject to lifting of COVID-19 restrictions to allow efficient project execution, currently expected towards fourth-quarter 2020.
The Ruche EEA covers 850 sq km with water depths from 70 m in the northeast corner to 650 m in the southwest corner. Six oil discoveries have been made on the license to date: Tortue, Hibiscus, Ruche, Ruche North East, Moubenga, and Walt Whitman. The crude is sweet with an API gravity of 28-30°.
BW Energy Gabon is operator with 73.5%. Partners are Tullow Oil, 10%; Panoro, 7.5%; and Gabon Oil Co., 9%.
Drilling & Production Quick Takes
CNOOC starts production in Bohai Bay field
CNOOC Ltd. commenced production at Nanbao 35-2 oil field S1 area in the central Bohai Bay with average water depth of 17 m. In addition to utilizing existing facilities of Nanbao 35-2, the production facility includes one unmanned wellhead platform. Three development wells are planned. The project is expected to reach peak production of about 1,800 bo/d in 2021.
The project is one of 10 the operator expected to put on stream this year as part of a plan to steadily increase its oil and gas reserves and production through 2022 (OGJ Online, Jan. 13, 2020; May 22, 2020; June 11, 2020).
CNOOC holds 100% interest of Nanbao 35-2 oilfield S1 area.
Origin Energy brings new gas on stream for APLNG
Origin Energy Ltd.’s new Talinga Orana gas gathering station is on stream in southeast Queensland, adding supply to the Australia Pacific LNG plant on Curtis Island near Gladstone.
The new facility, built and commissioned by contractors Monadelphous and MAN Energy Solutions, is a dual train gas gathering station about 30 km southwest of the Queensland town of Chinchilla.
The facility enables Origin Energy to maximize coal seam gas production from Talinga and Orana fields in the surrounding Surat basin.
Origin is also the upstream operator for Australia Pacific LNG (APLNG) and responsible for the development of its coal seam gas fields in both the Surat and Bowen basins of onshore Queensland along with the main transmission pipeline to transports gas to the LNG facility.
APLNG has been designed with a 30-year lifespan. It came on stream in 2015 and shipped its first LNG cargo in January 2016.
Origin and ConocoPhillips each hold 37.5% interest. Sinopec holds 25%.
Upland sets record rate in Niobrara
Upland Exploration Inc. achieved record initial production from its first Niobrara well from a planned seven-well pad recently completed in Weld County, Colo., including the highest reported 24-hr peak oil production per completed lateral length for any horizontal formation well within Denver Julesburg basin (for laterals over 4,000 ft, post-2010 spud).
Upland completed the Little Lady 22-1NH horizontal well (API: 05-123-49881) across 4,883 ft of productive lateral within the Niobrara B. The well achieved a 24-hr peak production rate of 1,396 boe/d on a two-stream basis (82% oil), the equivalent of 285 boe/d per thousand ft of completed interval. The well was completed with modern completion and stimulation techniques utilizing more than 1,800 lb of proppant and 2,200 gal of water per ft lateral length.
“While we continue to refine our methodology, a record result for the entire basin on our first well supports our overarching thesis that historically this great resource rock has been under-stimulated. The 22-1NH highlights the effectiveness of utilizing a modern completion design,” said David R. Watts, president.
Upland plans to drill an additional five wells on the Little Lady pad with development continuing later this year.
PROCESSING Quick Takes
Citgo, Phillips 66 update post-Laura operations
Citgo Petroleum Corp. and Phillips 66 are advancing efforts to restart their refining operations in Lake Charles, La., following damages sustained during Hurricane Laura’s Aug. 27 landfall along the US Gulf Coast in southwestern Louisiana (OGJ Online, Sept. 1, 2020).
With preliminary assessment of damages now completed and repair plans now in place, Citgo expects a phased restart of its 425,000-b/d Lake Charles refining complex, with all units anticipated to be back in service by mid to late-October, the operator said on Sept. 11.
While the refinery fared well overall, the complex sustained major damage to most of its cooling towers, minor damage to noncritical tanks, and a large amount of unidentified miscellaneous damage requiring noncritical repairs.
Citgo said repairing the refinery’s cooling towers and getting reliable electrical power from the utility grid are critical to restarting the complex. The operator, however, did not reveal a timeline for when repairs would begin.
Despite the complex’s ongoing outage, Citgo did confirm power supplied via generators at its terminals enabled the Lake Charles refinery rack to resume supply of ultra-low sulfur diesel (ULSD) to regional customers on Sept. 8.
As of Sept. 9, Phillips 66 said it was continuing to make necessary repairs and initial preparations at its 249,000-b/d Lake Charles refining complex in Westlake, La., for a proposed restart—contingent upon access to reliable electricity and other regional utilities—in the coming weeks.
While Phillips 66 already has resumed operations at both its Beaumont storage terminal in Nederland, Tex., and Gulf Coast Lubricants Plant (GCLP) in Sulphur, La., the company said operations at GCLP remain limited by electric power curtailments.
Hurricane Laura made landfall in near Cameron, La., at 1:00 a.m. CST on Aug. 27 as a Category 4 storm with maximum sustained winds of 150 mph and a minimum central pressure of 938 mb, according to the National Oceanic and Atmospheric Administration’s National Hurricane Center for the Atlantic region.
Lukoil lets contract for Nizhny Novgorod refinery
PJSC Lukoil has let a contract to Lummus Technology LLC’s Lummus Novolen Technology GMBH to provide technology licensing for a grassroots petrochemical unit to be built at subsidiary LLC Lukoil Nizhegorodnefteorgsintez’s (NNOS) 17 million-tonne/year Kstovo refinery in central Russia’s Nizhny Novgorod region.
As part of the contract, Lummus will license its proprietary Novolen gas-phase polypropylene (PP) technology for a new 500,000-tonnes/year PP unit at the refinery, as well as deliver basic design engineering, training and services, and catalyst supply for the project, the service provider said.
Lummus disclosed no details regarding a value of the contract or a timeframe for its work on the proposed project.
While Lukoil has yet to publicly reveal investment details on the new PP unit at Nizhny Novgorod, the operator confirmed in its latest investor presentation for September 2020 that Lukoil NNOS is progressing on construction of its previously announced deep conversion, delayed coking complex at the refinery (OGJ Online, Nov. 2, 2017).
To date, construction on the complex has reached 75%, with main long-lead items installed and work now under way to install onsite pipelines and technological equipment strapping, according to the September investor presentation.
Alongside a delayed coker, the 2.1-million tpy complex will include a diesel hydrotreater, a gas fractionator, hydrogen and sulfur production units, as well as infrastructure installations (OGJ Online, Aug. 30, 2018).
Once fully commissioned, the complex will enable the Nizhny Novgorod refinery to slash its production of fuel oil, increase refinery yields up to 95.5%, and achieve higher synergy with fluidized catalytic cracking (FCC) units already in operation at the site. Scheduled for full startup in 2021, the new complex will increase the refinery’s yield of light petroleum products to 76% from a current 64%.
Separately, Lukoil said construction has reached 82% completion on a grassroots deasphaltizing unit at subsidiary OOO Lukoil Volgogradneftepererabotka’s 14.8-million tpy Volgograd refinery in southern Russia (OGJ Online, Oct. 14, 2019). Further details regarding the new deasphaltizing unit have yet to be disclosed.
MOL Group lets contract for Danube refinery
Hungary’s MOL Group has let a contract to Frames Group BV, Alphen aan den Rijn, the Netherlands, to supply a new hydrogen recovery and purification system for converting low-purity hydrogen by-product into a high-purity gas stream for subsequent processing at its 8.1-million tonnes/year Duna refinery along the Danube River in Százhalombatta, near Budapest.
As part of the contract, Frames will deliver its skid-mounted, ready-to-install hydrogen recovery and purification system that—equipped with highly sensitive membrane technology from strategic partner Membrane Technology and Research Inc.—will recover hydrogen from vent recycled gas produced by the refinery’s mild hydrocracking unit to improve overall efficiency of hydrogen recovery at the refinery, as well as reduce operations costs at the site, the service provider said.
Alongside supply of the system, Frames also will provide site interface engineering and on-site supervision during installation, commissioning, and system startup.
The new hydrogen recovery and purification system at the Duna refinery comes as part of MOL Group’s ongoing commitment to improving efficiency of its processing operations, which in this case, will allow the Dana refinery reduce the volume of makeup hydrogen it receives from hydrogen plants by maximizing use of hydrogen already produced at the site, according to Frames.
The service provider disclosed neither a value of the contract nor a timeframe for startup of the hydrogen recovery system.
This latest contract follows MOL Group’s previous award to Frames for supply of its proprietary desalters (electrostatic coalescers) to be installed in the Duna refinery’s crude distillation unit as part of a new project to enable the site to process a broader range of crudes (OGJ Online, Mar. 15, 2019).
TRANSPORTATION Quick Takes
Magnolia LNG requests 5-year extension
Magnolia LNG LLC and Kinder Morgan Louisiana Pipeline LLC (KMLP) have requested a 5-year extension from the US Federal Energy Regulatory Commission (FERC) for completion of the 8.8-million tonne/year liquefaction plant and its supply infrastructure. Initial FERC approval of the project in 2016 mandated Apr. 15, 2021, completion. FERC authorized Magnolia LNG to begin site preparation in May 2017.
KMLP is to supply as much as 1.4 bcfd of natural gas to the plant via its Lake Charles Expansion project, construction of which is dependent on Magnolia LNG achieving a final investment decision (FID).
The companies cited unforeseeable developments in the global LNG market as prompting the request, noting attendant difficulties in entering into long-term offtake contracts and their effect on both securing project financing and reaching FID.
Australia-based LNG Ltd. earlier this year sold Magnolia LNG to a subsidiary of Glenfarne Group LLC.
CNC contracted for Beetaloo-Darwin pipeline design
The Northern Territory government has let a contract to CNC Project Management worth $327,000 (Aus.) to plan a corridor for a pipeline to transport potential onshore gas resources from Beetaloo basin to Darwin.
The proposed pipeline will travel close to Tennant Creek, Elliott, Newcastle Waters, Daly Waters, Larrimah, Mataranka, Katherine, Pine Creek, Marakai and finish at Middle Arm on Darwin Harbour.
The prefeasibility analysis will consider routing options, engineering, geotechnical, environmental, financial, land use and sacred site considerations involved in the creation of a new gas corridor.
The 100-m wide pipeline corridor is proposed to closely follow the Stuart Highway and through Katherine and Pine Creek to reach Darwin.
The move means that the new line could be used to hook up with the line from Tennant Creek to Mt Isa and send any gas extracted by fracturing from the Beetaloo basin west to Tennant Creek and then through the new pipeline to Darwin for either processing or direct export.
Several companies, including Origin Energy and Santos, are advanced in Betaloo basin shale gas exploration since the government dropped a moratorium in April 2018.
Analysts say that the costs of extracting the gas from deep underground in the Beetaloo and sending it to Australia’s east coast could make the potential reserves commercially unviable, whereas a pipeline to Darwin is a better option.
One of the jobs proposed for the consultants is to consider landowner arrangements where the pipeline is to be laid north to Darwin.
The aim is to provide clarity to the Gas Taskforce and the NT government for future decisions regarding acquisition of a corridor to transport gas from on shore reserves to existing and planned gas industry infrastructure.
The pipeline could be used to transport gas and/or liquids.
ADNOC lets crude terminal upgrade contracts
ADNOC Onshore, a subsidiary of Abu Dhabi National Oil Co., awarded two engineering, procurement, and construction contracts to upgrade two main oil lines (MOLs) and crude receiving infrastructure at Jebel Dhanna terminal in Abu Dhabi to increase the terminal’s flexibility. China Petroleum Pipeline Engineering Co. Ltd. – Abu Dhabi and Abu Dhabi-based Target Engineering Construction Co. LLC won the contracts.
The contract awarded to China Petroleum Pipeline Engineering is to replace the two MOLs which transport ADNOC’s premium grade Murban crude from its oilfields at Bab, Bu Hasa, North East Bab, and South East to Jebel Dhanna terminal, increasing their capacity by more than 30%. The contract is expected to be completed in 30 months.
Target Engineering will upgrade crude receiving at the Jebel Dhanna terminal, enabling ADNOC to use existing parts of the terminal to import Upper Zakum crude from offshore and non-system crude for delivery to the 417,000-b/d Ruwais Refinery West, about 12 km east of Jebel Dhanna and currently undergoing its own flexibility upgrade (OGJ Online, Aug. 17, 2020). The contract is expected to be completed in 20 months.
The EPC contracts have a combined value of around $245 million (AED 899.9 million). More than 50% of the total award value will flow back into the UAE’s economy under ADNOC’s in-country value program.
