GENERAL INTEREST Quick Takes
Qatar Petroleum to partner with Shell offshore Namibia
Qatar Petroleum has farmed in to two exploration blocks offshore the Republic of Namibia through an agreement with Shell.
Under the terms of the agreement, which is subject to customary approvals, Qatar Petroleum will hold a 45% participating interest in the PEL 39 exploration license pertaining to Block 2913A and Block 2914B, while Shell (operator) will hold a 45% interest, and the National Petroleum Corp. of Namibia (NAMCOR) will hold the remaining 10% interest.
A Royal Dutch Shell PLC subsidiary agreed to acquire Kosmos Energy’s 45% interest in the Namibia asset in September 2020 as part of a larger deal to acquire certain frontier exploration assets from the Dallas-based company (OGJ Online, Sept. 9, 2020).
According to Shell’s website, the company completed three seismic surveys on the license between 2014 and 2019 to identify geological structures below the seabed which might contain oil or gas. Having analyzed the data, the next step is to drill a well to determine whether oil or gas is present in quantities that could be extracted commercially, according to the website, but no timeframe was given.
The agreement marks the second in Namibia for Qatar Petroleum. In August 2019, the company entered into agreements with Total for participation in Blocks 2913B and 2912 offshore Namibia (OGJ Online, Aug. 27, 2019).
The PEL 39 blocks lie in water depths of about 2,500 m, covering an area of about 12,300 sq km.
ConocoPhillips reaffirms $5.5 billion capital plan
ConocoPhillips reaffirmed its full-year 2021 expected capital expenditure of $5.5 billion, with first quarter capex of $1.21-1.29 billion expected.
The company expects to report first-quarter 2021 production volumes of 1.47-1.49 MMboe/d, excluding Libya, which is estimated to be 40,000 boe/d. The overall first quarter estimate includes some 50,000 boe/d of unplanned weather impacts experienced throughout the Lower 48 as a result of Winter Storm Uri. Production in the Lower 48 was fully restored in March.
The preliminary first-quarter 2021 operational and financial updates as well as certain full-year 2021 guidance items reflect the combined company following the close of the Concho Resources transaction in January (OGJ Online. Oct. 19, 2020). Final first-quarter results will be reported on May 4.
In addition, the company expects to record before-tax earnings of $100 million related to commercial performance in the first quarter.
BHP to relinquish Tallaganda, Bunyip gas discoveries
BHP has applied to surrender the retention leases surrounding Tallaganda and Bunyip gas discoveries in deep water about 115 km off the Western Australian town of Exmouth in the offshore Carnarvon basin.
The surrender of WA-72-R and neighboring WA-73-R comes a month before the lease expiry date and returns the fields to stranded gas field status.
BHP discovered Tallaganda in second-half 2012 in what was then exploration permit WA-351-P and straddling the southern boundary into the company’s WA-335-P. Bunyip was found in WA-335-P in 2014.
Both discoveries are in the Triassic-age Mungaroo formation and were estimated to contain total gas reserves of around 500 bcf. Water depths in the region are about 1,200 m.
Initial development ideas centered on a tie-in to BHP’s Macedon field about 80 km away as the fields were not large enough to warrant a stand-alone LNG project with a pipeline to shore. That scheme lapsed.
BHP took out two 5-year retention leases (72-R and 73-R) in 2016 and began to consider a mini floating LNG development. However, BHP has decided to abandon its attempts to commercialize the two discoveries.
Exploration & Development Quick Takes
Eni makes light oil discovery offshore Angola
Eni made a light oil discovery in Block 15/06 offshore Angola that will be sidetracked updip to be placed in position as a producer well. Cuica-1 NFW, drilled on the Cuica exploration prospect inside the Cabaça development area close to the Armada Olombendo FPSO (East Hub), is estimated to hold 200-250 million bbl of oil in place.
Proximity to East Hub’s subsea network will allow for fast-track tie-in of the exploration well and relevant production, thus extending the Armada Olombendo FPSO production plateau, Eni said Apr. 6. Production is expected to begin within 6 months.
Drilled as a deviated well by the Libongos drillship in water depth of 500 m, the well reached a total vertical depth of 4,100 m and encountered an 80-m total column reservoir of light oil (38°API) in sandstones of Miocene age with good petrophysical properties. Data collection indicates an expected production capacity of 10,000 b/d of oil.
Cuica is the second significant oil discovery inside the existing Cabaça development area, and the first commercial discovery in Block 15/06 after re-launch of the exploration campaign following the COVID-19 pandemic and oil price drop in 2020. A 3-year extension of the block’s exploration period until November 2023 was recently granted.
Eni Angola operates the block with a 36.8421% interest. Sonangol P&P has 36.8421% and SSI Fifteen Ltd. has 26.3158%.
Neptune Energy: Appraisal well confirms significant discovery at Dugong
Neptune Energy will link its North Sea Dugong discovery to nearby infrastructure or pursue a standalone development after appraisal well (34/4-16 S) resulted in an updated recoverable resource volume estimate of 40-108 MMboe (OGJ Online, July 30, 2020; Jan. 7, 2021). The main objective—to delineate the discovery made in the Rannoch formation in wells 34/4-15 S (Dugong) and 34/4-15 A (Sjøpølse) in production license 882—was achieved by establishing the oil water contact.
The well encountered a 25-m oil column in the Rannoch formation, 22 m of which consists of sandstone of primarily moderate reservoir quality. The oil-water contact was encountered at a vertical depth of 3,443 m subsea, the Norwegian Petroleum Directorate noted in a Mar. 30 release following Neptune’s Mar. 29 statement.
The revised estimate is subject to further detailed analysis and review. A drill stem test on the well is planned at a later stage.
Dugong, 158 km west of Florø, Norway, lies at a water depth of 330 m, and is close to existing production facilities of Snorre and Statfjord fields. The reservoir lies at a depth of 3,250-3,500 m.
Well 34/4-15 S proved oil in reservoir rocks from the Middle Jurassic Rannoch formation. Well 34/4-15 A confirmed the oil discovery in the Rannoch formation and also proved an oil column in reservoir rocks from the Late Jurassic (most likely also Rannoch formation), NPD said.
Dugong license partners are Neptune Energy (operator, 45%), Petrolia NOCO (20%), Idemitsu Petroleum Norge (20%), and Concedo (15%).
SOCAR, Equinor consider Azerbaijan scenarios
State Oil Co. of Azerbaijan Republic (SOCAR) and Equinor are considering scenarios to accelerate exploration and drilling of Karabagh field prospects and possible reconsideration of the field development plan following encouraging preliminary exploration work.
The two companies met Mar. 16 to discuss Karabakh field development and the exploration of prospective structures carried out jointly by SOCAR and Equinor on equal sharing basis, SOCAR said in a Mar. 16 release.
In May 2018, SOCAR Karabakh and Equinor signed agreements to appraise and develop Karabagh oil field in the Caspian Sea and explore an area to the northwest designated Ashrafi-Dan Ulduzu-Aypara (OGJ Online, May 30, 2018). The exploration area lies 50 km east of Baku, around 14 km to the east of Azerbaijan mainland in water depths of 20-225 m. In March 2020, the companies confirmed a discovery at Karabagh (OGJ Online, Mar. 24, 2020).
Exploration of Ashrafi-Dan Ulduzu-Aypara began in second-half 2018 and 2D and 3D seismic exploration was completed in 2019. Results were processed in 2020, and interpretation is currently under way. Preliminary results demonstrated that oil and gas reserves in the prospects are higher than previously expected, SOCAR said, and exploration drilling may be carried out in the future to prove the reserves.
In the coming weeks, a joint working group of SOCAR and Equinor will consider various options for the continuation of the Karabakh project and explore opportunities for synergy between the development of Karabakh field and prospective new fields.
Buru to begin 2021 exploration program onshore Canning basin
Buru Energy Ltd., Perth, plans a three-well exploration program and a series of seismic surveys in its onshore Canning basin permits for the coming northern Australian drilling season in Western Australia.
The drilling program includes two wildcats and one development well.
First will be Kurrajong-1 in EP 391 followed by the Ungani-8 development well and then the second wildcat at Rafael-1 in EP 391.
Kurrajong-1 is a large structure, well defined by 3D seismic data and is expected to have similar good quality reservoir to Ungani oil field at similar depth.
Rafael-1 is a large structure defined by 2D seismic as having more than 450 m of mapped closure. It is interpreted as having similarities to Devonian aged carbonate structures in western Canada.
The seismic programs have been allocated to Terrex Pty Ltd. and will cover some 1,200 line-km, beginning with the Celestine 2D survey across EPs 457 and 458. The aim is to help fill Buru’s prospect inventory and enable continued drilling into the 2022 drilling season.
Buru will be carried for $16 million (Aus.) of the drilling costs of the wildcats and a significant part of the seismic program through a farm-in deal with Origin Energy executed in December 2020 (OGJ Online, Jan. 4, 2021).
Drilling & Production Quick Takes
Production start at Mero hits delay
Petróleo Brasileiro SA (Petrobras) has pushed back the start-up of production from Mero 1, through FPSO Guanabara, to first-quarter 2022 from fourth-quarter 2021.
The FPSO is being converted in China. The COVID-19 pandemic caused a delay in the unit’s construction, with a consequent adjustment to the schedule, Petrobras said in an Apr. 7 release.
The FPSO—with a processing capacity of 180,000 b/d of oil—will be installed in Mero oil field offshore Brazil in the northwestern Libra area of the Santos basin presalt.
The Mero 1 ultra-deepwater project will consist of up to 17 wells and the FPSO situated some 180 km offshore Rio de Janeiro at a water depth of 2,000 m subsea (OGJ Online, Dec. 18, 2017).
Petrobras is operator at Mero field with 40% interest. Partners are Shell Brasil Petróleo Ltda. (20%), Total E&P do Brasil Ltda. (20%), CNODC Brasil Petróleo e Gás Ltda. (10%), CNOOC Petroleum Brasil Ltda. (10%). State-owned Pré-Sal Petróleo SA is contract manager.
Lukoil increases Imilorskoye field production 20% y-o-y
Lukoil increased production from Imilorskoye field in the Khanty-Mansi Autonomous District in western Siberia by over 20% year-over-year and production drilling continues, the company said Mar. 17.
Cumulative oil output at field has exceeded five million tonnes since the start of its pilot commercial operation in 2014 (OGJ Online, Feb. 25, 2014; Oct. 8, 2014).
In 2020, 117 production wells with the average daily yield of 17 tonnes were brought on stream. In total, over 300 oil wells and 29 multi-well pads are in service. Eight new hydrocarbons reservoirs have been discovered since 2015.
Over 250 km of pipelines and 160 km of motorways have been constructed. The field support base features an administration and amenity complex, a mess hall, and an accommodation facility. There is also a booster pump station with a separation unit that intakes and degasses the crude coming from the field to prepare it for further transport.
Thameen-1 well testing complete, no flows at surface
Tethys Oil AB will suspend exploration well Thameen-1 on Block 49 onshore the Sultanate of Oman to allow further evaluation and later reentry after a well testing program unsuccessfully attempted to flow hydrocarbons to the surface. Down hole fluid samples were collected (OGJ Online, Mar. 1, 2021).
Thameen-1 was drilled to its final total depth in February 2021 and encountered hydrocarbon shows in the primary target, the Hasirah sandstone (OGJ Online, Jan. 4, 2021). Logs indicate a gross hydrocarbon column of close to 40 m. Sidewall cores, fluid samples, and pressure data will be further analyzed together with log analysis.
Tethys Oil AB, through subsidiary Tethys Oil Montasar Ltd., is operator and holds a 50% working interest in the exploration and production sharing agreement covering Block 49. In November 2020 EOG Resources Inc. agreed to a 50% farm-in (OGJ Online, Nov. 10, 2020). Final government approval was received in March 2021.
PROCESSING Quick Takes
Elixir books contingent CSG resources for Mongolian gas-fired power project
Elixir Energy Ltd., Adelaide, has booked independent contingent resources at its Nomgon coal seam gas discovery in southern Mongolia that will underpin a new gas-fired power generation project in the country.
The resources estimate, undertaken by ERC Equipoise Pte Ltd., has been confined to the initial selected gas supply area in the western sector of the Nomgon subbasin for the power project.
Elixir said the 2C recoverable gas resource is 24 bcf, which is more than sufficient to provide gas for the expected life of the plant.
The company has executed a memorandum of understanding with the Mongolian Ministry of Energy which provides a framework under which the parties will cooperate to investigate and then support a gas-fired power project in the south Gobi region.
Elixir has also entered into an agreement with Clarke Energy, a coal seam gas – power engineering specialist subsidiary of KOHLER Co., to conduct a feasibility study for the power project.
Elixir is aiming to establish an initial Mongolian plant of about 10 Mw capacity.
The company, which has a 100% interest in the Nomgon IX production sharing contract, plans to run production testing at the Nomgon discovery this year to establish stabilized water and potentially gas flow rates followed by a longer term pilot program beginning in 2022. Data will be used to finalize a development plan.
Elixir anticipates a 13-sq km area will be developed for the power plant over a multi-decade life. The mid-case number of wells is likely to be at least 36 and up to 107 depending on the style and type of development.
If successful, this will be Mongolia’s first gas-fired power station.
Russia incentivizes completion of Nizhny Novgorod refinery upgrade
Russia’s Ministry of Energy (MoE) has agreed to an incentive plan that will allow PJSC Lukoil to complete the deep conversion, delayed coking complex now under construction at subsidiary LLC Lukoil-Nizhegorodnefteorgsintez’s (NNOS) 17-million tonne/year Kstovo refinery in central Russia’s Nizhny Novgorod region (OGJ Online, Aug. 30, 2018; Nov. 2, 2017).
As part of the agreement, MoE has granted Lukoil an investment premium to the refundable excise tax on crude oil until Jan. 1, 2031, to support completion of construction on the deep conversion complex at Nizhny Novgorod refinery, Lukoil said on Mar. 24.
With core long-lead equipment now installed and installation of on-site pipelines and equipment piping currently under way, the new complex is scheduled for commissioning in fourth-quarter 2021.
Once in operation, the complex will enable the Nizhny Novgorod refinery to slash its production of fuel oil by 2.6 million tpy and increase annual output of Russian Class 5 (equivalent to Euro 5)-quality diesel fuel by 700,000 tpy, Lukoil said.
Additionally, the refinery’s overall product yield will increase to 97%, with yield of light products reaching 74-75%. Total fuel oil production from the refinery simultaneously will drop to less than 4%.
Nizhny Novgorod’s new deep conversion, delayed coking complex will include the following major units: a 2.11-million tpy delayed coker; a 1.5-million tpy combined diesel fuel and gasoline hydrotreater; a 50,000-cu m/hr hydrogen production unit; a 425,000-tpy gas fractionator; and an 81,000-tpy combined elemental sulfur-sulfuric acid production unit.
Azikel selects EPC contractor for Nigerian modular refinery
Azikel Group subsidiary Azikel Petroleum Ltd., Abuja, has let a contract to UAE-based Chemie Tech LLC to serve as engineering, procurement, and construction (EPC) contractor for its 12,000-b/sd hydroskimming modular refinery in Obunagha-Gbarain, Yenagoa, Bayelsa State, Nigeria.
As part of the lump-sum turnkey (LSTK) EPC contract, Chemie-Tech’s scope of work involves—but is not limited to—overall single-point responsibility for all project management, residual process engineering, detailed engineering, procurement, fabrication, installation, construction, testing, precommissioning, commissioning, and performance-guarantee test run (PGTR) run activities for the refinery, the service provider said.
Award of the LSTK EPC contract follows Chemie Tech’s completion of front-end engineering design (FEED) of the refinery’s outside battery limits (OSBL) areas as well early works on the project, the contractor said.
Originally targeted for startup in 2018, the modular refinery’s inside battery limits (ISBL) will host units for production of high-quality variants of LPG, gasoline, kerosine, aviation fuel, diesel, and heavy fuel oil (OGJ Online, Jan. 3, 2017).
To be built on modules mounted on skids, the modular refinery will be equipped with an unspecified catalytic reforming technology from Honeywell UOP LLC to produce reformate that will be blended to produce a premium motor spirit (PMS; gasoline) with an 89 research octane number clear (RONC).
The refinery will receive a reliable feedstock of Nigerian Bonny Light crude and condensate via pipeline directly from Royal Dutch Shell PLC’s Gbarian-Ubie Shell gas gathering plant at the site’s eastern boundary.
TRANSPORTATION Quick Takes
Cheniere begins Corpus Christi LNG Train 3 operations
Cheniere Energy Inc. has received approval from the US Federal Energy Regulatory Commission to put the third train at its 15-million tonne/year (tpy) Corpus Christi LNG plant in commercial service. Commissioning of Train 3 is complete, and Bechtel Oil, Gas, and Chemicals Inc. has turned over operations to Cheniere.
The train has been operating for evaluation and testing since August 2020. Trains 1 and 2 entered service in 2019.
Cheniere is also commercializing Stage 3 expansion at Corpus Christi, which proposes up to seven midscale trains that would add 10 million tpy of production.
Qatar Petroleum unwinding debut LNG joint venture
Qatar Petroleum will not be renewing its Qatargas Liquefied Natural Gas Co. Ltd. (QG1) joint venture with affiliates of Total SE, ExxonMobil Corp., Marubeni Corp., and Mitsui Group when it expires Dec. 31, 2021. Qatar Petroleum will become QG1’s sole owner.
QG1 produces 10 million tonnes/year of LNG from three trains. The QG 1 trains also produce about 51,000 b/d of condensate.
The joint venture ships primarily to Japan and Spain, using 11 135,000-cu m LNG carriers.
QG1 was established in 1984 and exported Qatar’s first LNG cargo. Chubu Electric was QG1’s foundation customer.
NextDecade, Oxy to develop Rio Grande Valley CCS
NextDecade Corp. and Oxy Low Carbon Ventures (OLCV), a subsidiary of Occidental Petroleum Corp., have executed a term sheet for the offtake and permanent geologic storage of CO2 captured from NextDecade’s planned 27-million tonne/year (tpy) Rio Grande LNG project in the Port of Brownsville, Tex. OLCV will offtake and transport CO2 from Rio Grande LNG and permanently sequester it in an underground geologic formation in the Rio Grande Valley.
Earlier this month, NextDecade announced the formation of Next Carbon Solutions, a wholly owned subsidiary that is expected to develop a 5-million tpy carbon capture and storage (CCS) project at Rio Grande LNG. The company also completed repricing of its lump-sum turnkey engineering, procurement, and construction (EPC) agreements with Bechtel Oil, Gas, and Chemicals Inc. for Rio Grande LNG’s first three trains (OGJ Online, Mar. 10, 2021).
NextDecade anticipates achieving final investment decision (FID) on a minimum of two trains at Rio Grande LNG in 2021 and FID on Next Carbon Solutions’ CCS project soon after FID on Rio Grande LNG.